Code of Virginia

Code of Virginia
8/21/2017

Virginia Electric Utility Regulation Act

§ 56-576. Definitions.

As used in this chapter:

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

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

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

"Commission" means the State Corporation Commission.

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

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

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

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

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

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

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

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

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

"Energy efficiency program" means a program that reduces the total amount of electricity that is required for the same process or activity implemented after the expiration of capped rates. Energy efficiency programs include equipment, physical, or program change designed to produce measured and verified reductions in the amount of electricity required to perform the same function and produce the same or a similar outcome. Energy efficiency programs may include, but are not limited to, (i) programs that result in improvements in lighting design, heating, ventilation, and air conditioning systems, appliances, building envelopes, and industrial and commercial processes; (ii) measures, such as but not limited to the installation of advanced meters, implemented or installed by utilities, that reduce fuel use or losses of electricity and otherwise improve internal operating efficiency in generation, transmission, and distribution systems; and (iii) customer engagement programs that result in measurable and verifiable energy savings that lead to efficient use patterns and practices. Energy efficiency programs include demand response, combined heat and power and waste heat recovery, curtailment, or other programs that are designed to reduce electricity consumption so long as they reduce the total amount of electricity that is required for the same process or activity. Utilities shall be authorized to install and operate such advanced metering technology and equipment on a customer's premises; however, nothing in this chapter establishes a requirement that an energy efficiency program be implemented on a customer's premises and be connected to a customer's wiring on the customer's side of the inter-connection without the customer's expressed consent.

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

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

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

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

"In the public interest," for purposes of assessing energy efficiency programs, describes an energy efficiency program if, among other factors, the net present value of the benefits exceeds the net present value of the costs as determined by the Commission upon consideration of the following four tests: (i) the Total Resource Cost Test; (ii) the Utility Cost Test (also referred to as the Program Administrator Test); (iii) the Participant Test; and (iv) the Ratepayer Impact Measure Test. Such determination shall include an analysis of all four tests, and a program or portfolio of programs shall not be rejected based solely on the results of a single test. In addition, an energy efficiency program may be deemed to be "in the public interest" if the program provides measurable and verifiable energy savings to low-income customers or elderly customers.

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

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

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

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

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

"Renewable energy" means energy derived from sunlight, wind, falling water, biomass, sustainable or otherwise, (the definitions of which shall be liberally construed), energy from waste, landfill gas, municipal solid waste, wave motion, tides, and geothermal power, and does not include energy derived from coal, oil, natural gas, or nuclear power. Renewable energy shall also include the proportion of the thermal or electric energy from a facility that results from the co-firing of biomass.

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

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

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

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

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

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

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

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

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

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

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

1999, c. 411; 2000, c. 991; 2001, c. 421; 2007, cc. 888, 933; 2008, cc. 272, 883; 2009, cc. 748, 824; 2012, cc. 46, 200, 210, 821; 2013, c. 494; 2014, cc. 212, 548.

§ 56-577. Schedule for transition to retail competition; Commission authority; exemptions; pilot programs.

A. Retail competition for the purchase and sale of electric energy shall be subject to the following provisions:

1. Each incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity shall join or establish a regional transmission entity, which entity may be an independent system operator, to which such utility shall transfer the management and control of its transmission system, subject to the provisions of § 56-579.

2. The generation of electric energy shall be subject to regulation as specified in this chapter.

3. From January 1, 2004, until the expiration or termination of capped rates, all retail customers of electric energy within the Commonwealth, regardless of customer class, shall be permitted to purchase electric energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth. After the expiration or termination of capped rates, and subject to the provisions of subdivisions 4 and 5, only individual retail customers of electric energy within the Commonwealth, regardless of customer class, whose demand during the most recent calendar year exceeded five megawatts but did not exceed one percent of the customer's incumbent electric utility's peak load during the most recent calendar year unless such customer had noncoincident peak demand in excess of 90 megawatts in calendar year 2006 or any year thereafter, shall be permitted to purchase electric energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth, except for any incumbent electric utility other than the incumbent electric utility serving the exclusive service territory in which such a customer is located, subject to the following conditions:

a. If such customer does not purchase electric energy from licensed suppliers after that date, such customer shall purchase electric energy from its incumbent electric utility.

b. Except as provided in subdivision 4, the demands of individual retail customers may not be aggregated or combined for the purpose of meeting the demand limitations of this provision, any other provision of this chapter to the contrary notwithstanding. For the purposes of this section, each noncontiguous site will nevertheless constitute an individual retail customer even though one or more such sites may be under common ownership of a single person.

c. If such customer does purchase electric energy from licensed suppliers after the expiration or termination of capped rates, it shall not thereafter be entitled to purchase electric energy from the incumbent electric utility without giving five years' advance written notice of such intention to such utility, except where such customer demonstrates to the Commission, after notice and opportunity for hearing, through clear and convincing evidence that its supplier has failed to perform, or has anticipatorily breached its duty to perform, or otherwise is about to fail to perform, through no fault of the customer, and that such customer is unable to obtain service at reasonable rates from an alternative supplier. If, as a result of such proceeding, the Commission finds it in the public interest to grant an exemption from the five-year notice requirement, such customer may thereafter purchase electric energy at the costs of such utility, as determined by the Commission pursuant to subdivision 3 d hereof, for the remainder of the five-year notice period, after which point the customer may purchase electric energy from the utility under rates, terms and conditions determined pursuant to § 56-585.1. However, such customer shall be allowed to individually purchase electric energy from the utility under rates, terms, and conditions determined pursuant to § 56-585.1 if, upon application by such customer, the Commission finds that neither such customer's incumbent electric utility nor retail customers of such utility that do not choose to obtain electric energy from alternate suppliers will be adversely affected in a manner contrary to the public interest by granting such petition. In making such determination, the Commission shall take into consideration, without limitation, the impact and effect of any and all other previously approved petitions of like type with respect to such incumbent electric utility. Any customer that returns to purchase electric energy from its incumbent electric utility, before or after expiration of the five-year notice period, shall be subject to minimum stay periods equal to those prescribed by the Commission pursuant to subdivision C 1.

d. The costs of serving a customer that has received an exemption from the five-year notice requirement under subdivision 3 c hereof shall be the market-based costs of the utility, including (i) the actual expenses of procuring such electric energy from the market, (ii) additional administrative and transaction costs associated with procuring such energy, including, but not limited to, costs of transmission, transmission line losses, and ancillary services, and (iii) a reasonable margin as determined pursuant to the provisions of subdivision A 2 of § 56-585.1. The methodology established by the Commission for determining such costs shall ensure that neither utilities nor other retail customers are adversely affected in a manner contrary to the public interest.

4. After the expiration or termination of capped rates, two or more individual nonresidential retail customers of electric energy within the Commonwealth, whose individual demand during the most recent calendar year did not exceed five megawatts, may petition the Commission for permission to aggregate or combine their demands, for the purpose of meeting the demand limitations of subdivision 3, so as to become qualified to purchase electric energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth under the conditions specified in subdivision 3. The Commission may, after notice and opportunity for hearing, approve such petition if it finds that:

a. Neither such customers' incumbent electric utility nor retail customers of such utility that do not choose to obtain electric energy from alternate suppliers will be adversely affected in a manner contrary to the public interest by granting such petition. In making such determination, the Commission shall take into consideration, without limitation, the impact and effect of any and all other previously approved petitions of like type with respect to such incumbent electric utility; and

b. Approval of such petition is consistent with the public interest.

If such petition is approved, all customers whose load has been aggregated or combined shall thereafter be subject in all respects to the provisions of subdivision 3 and shall be treated as a single, individual customer for the purposes of said subdivision. In addition, the Commission shall impose reasonable periodic monitoring and reporting obligations on such customers to demonstrate that they continue, as a group, to meet the demand limitations of subdivision 3. If the Commission finds, after notice and opportunity for hearing, that such group of customers no longer meets the above demand limitations, the Commission may revoke its previous approval of the petition, or take such other actions as may be consistent with the public interest.

5. After the expiration or termination of capped rates, individual retail customers of electric energy within the Commonwealth, regardless of customer class, shall be permitted:

a. To purchase electric energy provided 100 percent from renewable energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth, other than any incumbent electric utility that is not the incumbent electric utility serving the exclusive service territory in which such a customer is located, if the incumbent electric utility serving the exclusive service territory does not offer an approved tariff for electric energy provided 100 percent from renewable energy; and

b. To continue purchasing renewable energy pursuant to the terms of a power purchase agreement in effect on the date there is filed with the Commission a tariff for the incumbent electric utility that serves the exclusive service territory in which the customer is located to offer electric energy provided 100 percent from renewable energy, for the duration of such agreement.

6. A tariff for one or more classes of residential customers filed with the Commission for approval by a cooperative on or after July 1, 2010, shall be deemed to offer a tariff for electric energy provided 100 percent from renewable energy if it provides undifferentiated electric energy and the cooperative retires a quantity of renewable energy certificates equal to 100 percent of the electric energy provided pursuant to such tariff. A tariff for one or more classes of nonresidential customers filed with the Commission for approval by a cooperative on or after July 1, 2012, shall be deemed to offer a tariff for electric energy provided 100 percent from renewable energy if it provides undifferentiated electric energy and the cooperative retires a quantity of renewable energy certificates equal to 100 percent of the electric energy provided pursuant to such tariff. For purposes of this section, "renewable energy certificate" means, with respect to cooperatives, a tradable commodity or instrument issued by a regional transmission entity or affiliate or successor thereof in the United States that validates the generation of electricity from renewable energy sources or that is certified under a generally recognized renewable energy certificate standard. One renewable energy certificate equals 1,000 kWh or one MWh of electricity generated from renewable energy. A cooperative offering electric energy provided 100 percent from renewable energy pursuant to this subdivision that involves the retirement of renewable energy certificates shall disclose to its retail customers who express an interest in purchasing energy pursuant to such tariff (i) that the renewable energy is comprised of the retirement of renewable energy certificates, (ii) the identity of the entity providing the renewable energy certificates, and (iii) the sources of renewable energy being offered.

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

C. 1. By January 1, 2002, the Commission shall promulgate regulations establishing whether and, if so, for what minimum periods, customers who request service from an incumbent electric utility pursuant to subsection D of § 56-582 or a default service provider, after a period of receiving service from other suppliers of electric energy, shall be required to use such service from such incumbent electric utility or default service provider, as determined to be in the public interest by the Commission.

2. Subject to (i) the availability of capped rate service under § 56-582, and (ii) the transfer of the management and control of an incumbent electric utility's transmission assets to a regional transmission entity after approval of such transfer by the Commission under § 56-579, retail customers of such utility (a) purchasing such energy from licensed suppliers and (b) otherwise subject to minimum stay periods prescribed by the Commission pursuant to subdivision 1, shall nevertheless be exempt from any such minimum stay obligations by agreeing to purchase electric energy at the market-based costs of such utility or default providers after a period of obtaining electric energy from another supplier. Such costs shall include (i) the actual expenses of procuring such electric energy from the market, (ii) additional administrative and transaction costs associated with procuring such energy, including, but not limited to, costs of transmission, transmission line losses, and ancillary services, and (iii) a reasonable margin. The methodology of ascertaining such costs shall be determined and approved by the Commission after notice and opportunity for hearing and after review of any plan filed by such utility to procure electric energy to serve such customers. The methodology established by the Commission for determining such costs shall be consistent with the goals of (a) promoting the development of effective competition and economic development within the Commonwealth as provided in subsection A of § 56-596, and (b) ensuring that neither incumbent utilities nor retail customers that do not choose to obtain electric energy from alternate suppliers are adversely affected.

3. Notwithstanding the provisions of subsection D of § 56-582 and subsection C of § 56-585, however, any such customers exempted from any applicable minimum stay periods as provided in subdivision 2 shall not be entitled to purchase retail electric energy thereafter from their incumbent electric utilities, or from any distributor required to provide default service under subsection B of § 56-585, at the capped rates established under § 56-582, unless such customers agree to satisfy any minimum stay period then applicable while obtaining retail electric energy at capped rates.

4. The Commission shall promulgate such rules and regulations as may be necessary to implement the provisions of this subsection, which rules and regulations shall include provisions specifying the commencement date of such minimum stay exemption program.

1999, c. 411; 2001, c. 748; 2003, cc. 795, 990; 2004, c. 827; 2007, cc. 888, 933; 2010, cc. 326, 397.

§ 56-578. Nondiscriminatory access to transmission and distribution system.

A. All distributors shall have the obligation to connect any retail customer, including those using distributed generation, located within its service territory to those facilities of the distributor that are used for delivery of retail electric energy, subject to Commission rules and regulations and approved tariff provisions relating to connection of service.

B. Except as otherwise provided in this chapter, every distributor shall provide distribution service within its service territory on a basis which is just, reasonable, and not unduly discriminatory to suppliers of electric energy, including distributed generation, as the Commission may determine. The distribution services provided to each supplier of electric energy shall be comparable in quality to those provided by the distribution utility to itself or to any affiliate.

C. The Commission shall establish interconnection standards to ensure transmission and distribution safety and reliability, which standards shall not be inconsistent with nationally recognized standards acceptable to the Commission. In adopting standards pursuant to this subsection, the Commission shall seek to prevent barriers to new technology and shall not make compliance unduly burdensome and expensive. The Commission shall determine questions about the ability of specific equipment to meet interconnection standards.

D. The Commission shall consider developing expedited permitting processes for small generation facilities of fifty megawatts or less. The Commission shall also consider developing a standardized permitting process and interconnection arrangements for those power systems less than 500 kilowatts which have demonstrated approval from a nationally recognized testing laboratory acceptable to the Commission.

E. Upon the separation and deregulation of the generation function and services of incumbent electric utilities, the Commission shall retain jurisdiction over utilities' electric transmission function and services, to the extent not preempted by federal law. Nothing in this section shall impair the Commission's authority under §§ 56-46.1, 56-46.2, and 56-265.2 with respect to the construction of electric transmission facilities.

1999, c. 411; 2007, cc. 888, 933.

§ 56-579. Regional transmission entities.

A. As set forth in § 56-577, each incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity shall join or establish a regional transmission entity, which hereafter may be referred to as "RTE," to which such utility shall transfer the management and control of its transmission assets, subject to the following:

1. No such incumbent electric utility shall transfer to any person any ownership or control of, or any responsibility to operate, any portion of any transmission system located in the Commonwealth prior to July 1, 2004, and without obtaining, following notice and hearing, the prior approval of the Commission, as hereinafter provided. However, each incumbent electric utility shall file an application for approval pursuant to this section by July 1, 2003, and shall transfer management and control of its transmission assets to a regional transmission entity by January 1, 2005, subject to Commission approval as provided in this section.

2. The Commission shall develop rules and regulations under which any such incumbent electric utility owning, operating, controlling, or having an entitlement to transmission capacity within the Commonwealth, may transfer all or part of such control, ownership or responsibility to an RTE, upon such terms and conditions that the Commission determines will:

a. Promote:

(1) Practices for the reliable planning, operating, maintaining, and upgrading of the transmission systems and any necessary additions thereto; and

(2) Policies for the pricing and access for service over such systems that are safe, reliable, efficient, not unduly discriminatory and consistent with the orderly development of competition in the Commonwealth;

b. Be consistent with lawful requirements of the Federal Energy Regulatory Commission;

c. Be effectuated on terms that fairly compensate the transferor;

d. Generally promote the public interest, and are consistent with (i) ensuring that consumers' needs for economic and reliable transmission are met and (ii) meeting the transmission needs of electric generation suppliers both within and without this Commonwealth, including those that do not own, operate, control or have an entitlement to transmission capacity.

B. The Commission shall also adopt rules and regulations, with appropriate public input, establishing elements of regional transmission entity structures essential to the public interest, which elements shall be applied by the Commission in determining whether to authorize transfer of ownership or control from an incumbent electric utility to a regional transmission entity.

C. The Commission shall, to the fullest extent permitted under federal law, participate in any and all proceedings concerning regional transmission entities furnishing transmission services within the Commonwealth, before the Federal Energy Regulatory Commission. Such participation may include such intervention as is permitted state utility regulators under Federal Energy Regulatory Commission rules and procedures.

D. Nothing in this section shall be deemed to abrogate or modify:

1. The Commission's authority over transmission line or facility construction, enlargement or acquisition within this Commonwealth, as set forth in Chapter 10.1 (§ 56-265.1 et seq.) of this title;

2. The laws of this Commonwealth concerning the exercise of the right of eminent domain by a public service corporation pursuant to the provisions of Article 5 (§ 56-257 et seq.) of Chapter 10 of this title; or

3. The Commission's authority over retail electric energy sold to retail customers within the Commonwealth by licensed suppliers of electric service, including necessary reserve requirements, all as specified in § 56-587.

E. For purposes of this section, transmission capacity shall not include capacity that is primarily operated in a distribution function, as determined by the Commission, taking into consideration any binding federal precedents.

F. Any request to the Commission for approval of such transfer of ownership or control of or responsibility for transmission facilities shall include a study of the comparative costs and benefits thereof, which study shall analyze the economic effects of the transfer on consumers, including the effects of transmission congestion costs. The Commission may approve such a transfer if it finds, after notice and hearing, that the transfer satisfies the conditions contained in this section.

G. The Commission shall report annually to the Commission on Electric Utility Regulation its assessment of the practices and policies of the RTE. Such report shall set forth actions taken by the Commission regarding requests for the approval of any transfer of ownership or control of transmission facilities to an RTE, including a description of the economic effects of such proposed transfers on consumers.

1999, c. 411; 2001, c. 576; 2003, cc. 885, 990; 2007, cc. 888, 933; 2008, c. 883.

§ 56-580. Transmission and distribution of electric energy.

A. Subject to the provisions of § 56-585.1, the Commission shall continue to regulate pursuant to this title the distribution of retail electric energy to retail customers in the Commonwealth and, to the extent not prohibited by federal law, the transmission of electric energy in the Commonwealth.

B. The Commission shall continue to regulate, to the extent not prohibited by federal law, the reliability, quality and maintenance by transmitters and distributors of their transmission and retail distribution systems.

C. The Commission shall develop codes of conduct governing the conduct of incumbent electric utilities and affiliates thereof when any such affiliates provide, or control any entity that provides, generation, distribution, or transmission services, to the extent necessary to prevent impairment of competition. Nothing in this chapter shall prevent an incumbent electric utility from offering metering options to its customers.

D. The Commission shall permit the construction and operation of electrical generating facilities in Virginia upon a finding that such generating facility and associated facilities (i) will have no material adverse effect upon reliability of electric service provided by any regulated public utility, (ii) are required by the public convenience and necessity, if a petition for such permit is filed after July 1, 2007, and if they are to be constructed and operated by any regulated utility whose rates are regulated pursuant to § 56-585.1, and (iii) are not otherwise contrary to the public interest. In review of a petition for a certificate to construct and operate a generating facility described in this subsection, the Commission shall give consideration to the effect of the facility and associated facilities on the environment and establish such conditions as may be desirable or necessary to minimize adverse environmental impact as provided in § 56-46.1, unless exempt as a small renewable energy project for which the Department of Environmental Quality has issued a permit by rule pursuant to Article 5 (§ 10.1-1197.5 et seq.) of Chapter 11.1 of Title 10.1. In order to avoid duplication of governmental activities, any valid permit or approval required for an electric generating plant and associated facilities issued or granted by a federal, state or local governmental entity charged by law with responsibility for issuing permits or approvals regulating environmental impact and mitigation of adverse environmental impact or for other specific public interest issues such as building codes, transportation plans, and public safety, whether such permit or approval is prior to or after the Commission's decision, shall be deemed to satisfy the requirements of this section with respect to all matters that (i) are governed by the permit or approval or (ii) are within the authority of, and were considered by, the governmental entity in issuing such permit or approval, and the Commission shall impose no additional conditions with respect to such matters. Nothing in this section shall affect the ability of the Commission to keep the record of a case open. Nothing in this section shall affect any right to appeal such permits or approvals in accordance with applicable law. In the case of a proposed facility located in a region that was designated as of July 1, 2001, as serious nonattainment for the one-hour ozone standard as set forth in the federal Clean Air Act, the Commission shall not issue a decision approving such proposed facility that is conditioned upon issuance of any environmental permit or approval. The Commission shall complete any proceeding under this section, or under any provision of the Utility Facilities Act (§ 56-265.1 et seq.), involving an application for a certificate, permit, or approval required for the construction or operation by a public utility of a small renewable energy project as defined in § 10.1-1197.5, within nine months following the utility's submission of a complete application therefore. Small renewable energy projects as defined in § 10.1-1197.5 are in the public interest and in determining whether to approve such project, the Commission shall liberally construe the provisions of this title.

E. Nothing in this section shall impair the distribution service territorial rights of incumbent electric utilities, and incumbent electric utilities shall continue to provide distribution services within their exclusive service territories as established by the Commission. Subject to the provisions of § 56-585.1, the Commission shall continue to exercise its existing authority over the provision of electric distribution services to retail customers in the Commonwealth including, but not limited to, the authority contained in Chapters 10 (§ 56-232 et seq.) and 10.1 (§ 56-265.1 et seq.) of this title.

F. Nothing in this chapter shall impair the exclusive territorial rights of an electric utility owned or operated by a municipality as of July 1, 1999, or by an authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403. Nor shall any provision of this chapter apply to any such electric utility unless (i) that municipality or that authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403 elects to have this chapter apply to that utility or (ii) that utility, directly or indirectly, sells, offers to sell or seeks to sell electric energy to any retail customer eligible to purchase electric energy from any supplier in accordance with § 56-577 if that retail customer is outside the geographic area that was served by such municipality as of July 1, 1999, except (a) any area within the municipality that was served by an incumbent public utility as of that date but was thereafter served by an electric utility owned or operated by a municipality or by an authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403 pursuant to the terms of a franchise agreement between the municipality and the incumbent public utility, or (b) where the geographic area served by an electric utility owned or operated by a municipality is changed pursuant to mutual agreement between the municipality and the affected incumbent public utility in accordance with § 56-265.4:1. If an electric utility owned or operated by a municipality as of July 1, 1999, or by an authority created by a governmental unit exempt from the referendum requirement of § 15.2-5403 is made subject to the provisions of this chapter pursuant to clause (i) or (ii) of this subsection, then in such event the provisions of this chapter applicable to incumbent electric utilities shall also apply to any such utility, mutatis mutandis.

G. The applicability of all provisions of this chapter except § 56-594 to any investor-owned incumbent electric utility supplying electric service to retail customers on January 1, 2003, whose service territory assigned to it by the Commission is located entirely within Dickenson, Lee, Russell, Scott, and Wise Counties shall be suspended effective July 1, 2003, so long as such utility does not provide retail electric services in any other service territory in any jurisdiction to customers who have the right to receive retail electric energy from another supplier. During any such suspension period, the utility's rates shall be (i) its capped rates established pursuant to § 56-582 for the duration of the capped rate period established thereunder, and (ii) determined thereafter by the Commission on the basis of such utility's prudently incurred costs pursuant to Chapter 10 (§ 56-232 et seq.) of this title.

H. The expiration date of any certificates granted by the Commission pursuant to subsection D, for which applications were filed with the Commission prior to July 1, 2002, shall be extended for an additional two years from the expiration date that otherwise would apply.

1999, c. 411; 2000, c. 991; 2001, cc. 738, 748, 755; 2002, c. 483; 2003, c. 719; 2004, cc. 262, 827; 2006, cc. 811, 819, 929, 941; 2007, cc. 877, 888, 933; 2009, cc. 808, 854.

§ 56-581. Regulation of rates subject to Commission's jurisdiction.

A. After the expiration or termination of capped rates except as provided in § 56-585.1, the Commission shall regulate the rates of investor-owned incumbent electric utilities for the transmission of electric energy, to the extent not prohibited by federal law, and for the generation of electric energy and the distribution of electric energy to retail customers pursuant to § 56-585.1.

B. Beginning July 1, 1999, and thereafter, no cooperative that was a member of a power supply cooperative on January 1, 1999, shall be obligated to file any rate rider as a consequence of an increase or decrease in the rates, other than fuel costs, of its wholesale supplier, nor must any adjustment be made to such cooperative's rates as a consequence thereof.

C. Except for the provision of default services under § 56-585 or emergency services in § 56-586, nothing in this chapter shall authorize the Commission to regulate the rates or charges for electric service to the Commonwealth and its municipalities.

1999, c. 411; 2000, c. 991; 2007, cc. 888, 933.

§ 56-581.1. Repealed.

Repealed by Acts 2007, cc. 888 and 933, cl. 2.

§ 56-582. Rate caps.

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

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

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

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

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

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

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

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

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

1999, c. 411; 2000, cc. 942, 991; 2001, c. 748; 2004, c. 827; 2007, cc. 888, 933; 2008, c. 883.

§ 56-583. Repealed.

Repealed by Acts 2007, cc. 888 and 933, cl. 2.

§ 56-584. Stranded costs.

Just and reasonable net stranded costs, to the extent that they exceed zero value in total for the incumbent electric utility, shall be recoverable by each incumbent electric utility provided each incumbent electric utility shall only recover its just and reasonable net stranded costs through either capped rates as provided in § 56-582. To the extent not preempted by federal law, the establishment by the Commission of wires charges for any distribution cooperative shall be conditioned upon such cooperative entering into binding commitments by which it will pay to any power supply cooperative of which such distribution cooperative is or was a member, as compensation for such power supply cooperative's stranded costs, all or part of the proceeds of such wires charges, as determined by the Commission.

1999, c. 411; 2007, cc. 888, 933.

§ 56-585. Default service.

A. The Commission shall, after notice and opportunity for hearing, (i) determine the components of default service and (ii) establish one or more programs making such services available to retail customers requiring them during the availability throughout the Commonwealth of customer choice for all retail customers as established pursuant to § 56-577. For purposes of this chapter, "default service" means service made available under this section to retail customers who (i) do not affirmatively select a supplier, (ii) are unable to obtain service from an alternative supplier, or (iii) have contracted with an alternative supplier who fails to perform. Availability of default service shall expire upon the expiration or termination of capped rates.

B. A distributor shall have the obligation and right to be the supplier of default services in its certificated service territory, and shall do so, in a safe and reliable manner, at rates determined pursuant to subsection C; however, the Commission may not require a distributor, or affiliate thereof, to provide any such services outside the territory in which such distributor provides service.

C. Until the expiration or termination of capped rates, the rates for default service shall equal the capped rates established pursuant to subdivision A 2 of § 56-582.

D. A distribution electric cooperative, or one or more affiliates thereof, shall have the obligation and right to be the supplier of default services in its certificated service territory. A distribution electric cooperative's rates for such default services shall be the capped rate for the duration of the capped rate period. Subsections B and C shall not apply to a distribution electric cooperative or its rates. Such default services, for the purposes of this subsection, shall include the supply of electric energy.

1999, c. 411; 2000, c. 991; 2001, c. 748; 2003, c. 885; 2004, c. 827; 2007, cc. 888, 933.

§ 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 biennial 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. The first such review shall utilize the two successive 12-month test periods ending December 31, 2010. However, the Commission may, in its discretion, elect to stagger its biennial reviews of utilities by utilizing the two successive 12-month test periods ending December 31, 2010, for a Phase I Utility, and utilizing the two successive 12-month test periods ending December 31, 2011, for a Phase II Utility, with subsequent proceedings utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such 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, fair rates of return on common equity applicable separately to the generation and distribution services of such utility, and for the two such services combined, shall be determined by the Commission during each such biennial review, as follows:

a. 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 subject to such biennial review, nor shall the Commission set such return more than 300 basis points higher than such average.

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

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

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

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

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

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

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

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

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

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 biennial review.

3. Each such utility shall make a biennial filing by March 31 of every other year, beginning in 2011, consisting of the schedules contained in the Commission's rules governing utility rate increase applications; however, if the Commission elects to stagger the dates of the biennial reviews of utilities as provided in subdivision 1, then each Phase I Utility shall commence biennial filings in 2011 and each Phase II Utility shall commence biennial filings in 2012. Such filing shall encompass the two successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted, and in every such case the filing for each year shall be identified separately and shall be segregated from any other year encompassed by the filing. If the Commission determines that rates should be revised or credits be applied to customers' bills pursuant to subdivision 8 or 9, any rate adjustment clauses previously implemented pursuant to subdivision 5 or those related to facilities utilizing simple-cycle combustion turbines described in subdivision 6, shall be combined with the utility's costs, revenues and investments until the amounts that are the subject of such rate adjustment clauses are fully recovered. The Commission shall combine such clauses with the utility's costs, revenues and investments only after it makes its initial determination with regard to necessary rate revisions or credits to customers' bills, and the amounts thereof, but after such clauses are combined as herein specified, they shall thereafter be considered part of the utility's costs, revenues, and investments for the purposes of future biennial review proceedings. A Phase I Utility shall delay for one year the filing of its biennial review from March 31, 2013, to March 31, 2014, and shall not defer on its books for future recovery any costs incurred during calendar year 2011, other than as provided in subdivision 7 or § 56-249.6, and its subsequent biennial filing shall be made by March 31, 2016, and every two years thereafter.

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

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

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

b. Projected and actual costs for the utility to design and operate fair and effective peak-shaving programs. 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, including a margin to be recovered on operating expenses, which margin for the purposes of this section shall be equal to the general rate of return on common equity determined as described in subdivision 2. The Commission shall only approve such a petition if it finds that the program is in the public interest. As part of such cost recovery, the Commission, if requested by the utility, shall allow for the recovery of revenue reductions related to energy efficiency programs. The Commission shall only allow such recovery to the extent that the Commission determines such revenue has not been recovered through margins from incremental off-system sales as defined in § 56-249.6 that are directly attributable to energy efficiency programs.

None of the costs of new energy efficiency programs of an electric utility, including recovery of revenue reductions, shall be assigned to any customer that has a verifiable history of having used more than 10 megawatts of demand from a single meter of delivery. Nor shall any of the costs of new energy efficiency programs of an electric utility, including recovery of revenue reductions, be incurred by any large general service customer as defined herein that has notified the utility of non-participation in such energy efficiency program or programs. A large general service customer is a customer that has a verifiable history of having used more than 500 kilowatts of demand from a single meter of delivery. Non-participation in energy efficiency programs shall be allowed by the Commission if 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 November 15, 2009, promulgate rules and regulations to accommodate the process under which such large general service customers shall file notice for such an exemption and (i) establish the administrative procedures by which eligible customers will notify the utility and (ii) define the standard criteria that must be satisfied by an applicant in order to notify the utility. In promulgating such rules and regulations, the Commission may 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. The notice of non-participation by a large general service customer, to be given by March 1 of a given year, shall be for the duration of the service life of the customer's energy efficiency program. The Commission on its own motion may initiate steps necessary to verify such non-participants' achievement of energy efficiency if the Commission has a body of evidence that the non-participant has knowingly misrepresented its energy efficiency achievement. A utility shall not charge such large general service customer, as defined by the Commission, 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 participation in a renewable energy portfolio standard program pursuant to § 56-585.2 that are not recoverable under subdivision 6. The Commission shall approve such a petition allowing the recovery of such costs as are provided for in a program approved pursuant to § 56-585.2;

e. Projected and actual costs of projects that the Commission finds to be necessary to comply with state or federal environmental laws or regulations applicable to generation facilities used to serve the utility's native load obligations. The Commission shall approve such a petition if it finds that such costs are necessary to comply with such environmental laws or regulations; and

f. Projected and actual costs, not currently in rates, for the utility to design, implement, and operate programs approved by the Commission that accelerate the vegetation management of distribution rights-of-way. No costs shall be allocated to or recovered from customers that are served within the large general service rate classes for a Phase II Utility or that are served at subtransmission or transmission voltage, or take delivery at a substation served from subtransmission or transmission voltage, for a Phase I Utility.

The Commission shall have the authority to determine the duration or amortization period for any 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, or (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; 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 biennial 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), 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). 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 described in clause (i) or (ii) shall demonstrate 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), or (iii) 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. 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), or (iii) 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, 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 500 megawatts, that use energy derived from sunlight and are located in the Commonwealth, 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. There shall be a rebuttable presumption that the conversion of such facilities will provide local and system-wide benefits, that such new underground facilities are cost beneficial, and that the costs associated with such new underground facilities are reasonably and prudently incurred. 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:

aType of Generation Facility
Basis Points
First Portion of Service Life
bNuclear-powered
200
Between 12 and 25 years
cCarbon capture compatible, clean-coal powered
200
Between 10 and 20 years
dRenewable powered, other than landfill gas powered
200
Between 5 and 15 years
eCoalbed methane gas powered
150
Between 5 and 15 years
fLandfill gas powered
200
Between 5 and 15 years
gConventional coal or combined-cycle combustion turbine
100
Between 10 and 20 years

For generating facilities other than those utilizing nuclear power constructed pursuant to clause (ii) or those utilizing energy derived from offshore wind, as of July 1, 2013, 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.

For generating facilities within the Commonwealth utilizing nuclear power or those utilizing energy derived from offshore wind projects located in waters off the Commonwealth's Atlantic shoreline, such facilities shall continue to be eligible for an enhanced rate of return on common equity during the construction phase of the facility and the approved first portion of its service life of between 12 and 25 years in the case of a facility utilizing nuclear power and for a service life of between 5 and 15 years in the case of a facility utilizing energy derived from offshore wind, provided, however, that, as of July 1, 2013, the enhanced return for such facilities constructed pursuant to clause (ii) shall be 100 basis points, which shall be added to the utility's general rate of return as determined under subdivision 2. 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 biennial review filed after July 1, 2014. Thirty percent of all costs of such 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 biennial 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 nuclear generation facility or facilities are in the public interest.

In connection with planning to meet forecasted demand for electric generation supply and assure the adequate and sufficient reliability of service, consistent with § 56-598, planning and development activities for a new utility-owned and utility-operated generating facility or facilities utilizing energy derived from sunlight with an aggregate capacity of 500 megawatts, or from offshore wind, are in the public interest.

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 § 45.1-361.1, 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 from time to time for such utility pursuant to subdivision 2. In any proceeding under this subdivision conducted prior to the conclusion of the first biennial review for such utility, the Commission shall determine a general rate of return for such utility in the same manner as it would in a biennial review proceeding.

Notwithstanding any other provision of this subdivision, if the Commission finds during the biennial review conducted for a Phase II Utility in 2018 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.

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 biennial filings under subdivision 3 made on and after July 1, 2014, and (b) pursuant to § 56-245 or the Commission's rules governing utility rate increase applications as provided in subsection B. This provision shall not be deemed to change or reset base rates.

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

8. In any biennial review proceeding, 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: costs associated with asset impairments related to early retirement determinations made by the utility prior to December 31, 2012, for utility generation plant; 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 biennial review proceeding, authorize deferred recovery of such costs and allow the utility to amortize and recover such deferred costs over future periods as determined by the Commission. The aggregate amount of such deferred costs shall not exceed an amount that would, together with the utility's other costs, revenues, and investments to be recovered through rates for generation and distribution services, cause the utility's earned return on its generation and distribution services to exceed the fair rate of return authorized under subdivision 2, less 50 basis points, for the combined test periods under review or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, to exceed the fair rate of return authorized under subdivision 2 less 70 basis points. Nothing in this section shall limit the Commission's authority, pursuant to the provisions of Chapter 10 (§ 56-232 et seq.), including specifically § 56-235.2, following the review of combined test period earnings of the utility in a biennial review, for normalization of nonrecurring test period costs and annualized adjustments for future costs, in determining any appropriate increase or decrease in the utility's rates for generation and distribution services pursuant to subdivision 8 a or 8 c.

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

a. 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, 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;

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 subdivision 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. Such biennial review is the second consecutive biennial review in which the utility has, during the test period or test periods under review, considered as a whole, earned more than 50 basis points above a fair combined rate of return on its generation and distribution services or, for any test period commencing after December 31, 2012, for a Phase II Utility and after December 31, 2013, for a Phase I Utility, more than 70 basis points above a fair combined rate of return on its generation and distribution services, as determined in subdivision 2, without regard to any return on common equity or other matter determined with respect to facilities described in subdivision 6, the Commission shall, subject to the provisions of subdivision 9 and in addition to the actions authorized in subdivision b, also order reductions to the utility's rates it finds appropriate. However, 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.

The Commission's final order regarding such biennial 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 biennial review shall apply, for purposes of reviewing the utility's earnings on its rates for generation and distribution services, to the entire two successive 12-month test periods ending December 31 immediately preceding the year of the utility's subsequent biennial review filing under subdivision 3.

9. If, as a result of a biennial 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 biennial 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. Any such credits shall be amortized and allocated among customer classes in the manner provided by subdivision 8 b. For purposes of this subdivision:

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

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

10. For purposes of this section, the Commission shall regulate the rates, terms and conditions of any utility subject to this section on a stand-alone basis utilizing the actual end-of-test period capital structure and cost of capital of such utility, 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 Energy Policy set forth in §§ 67-101 and 67-102, and shall also consider whether the costs of such resources is likely to result in unreasonable increases in rates paid by consumers.

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

2007, cc. 888, 933; 2008, c. 476; 2009, c. 824; 2011, cc. 236, 367, 371, 380, 382; 2012, c. 435; 2013, c. 2; 2014, cc. 212, 541, 548, 550; 2015, cc. 37, 599; 2016, c. 3; 2017, cc. 246, 564, 583, 820.

§ 56-585.1:1. Transitional Rate Period: review of rates, terms and conditions for utility generation facilities.

Notwithstanding the provisions of §§ 56-249.6 and 56-585.1:

A. No biennial reviews of the rates, terms, and conditions for any service of a Phase I Utility, as defined in § 56-585.1, shall be conducted at any time by the State Corporation Commission for the four successive 12-month test periods beginning January 1, 2014, and ending December 31, 2017. No biennial reviews of the rates, terms, and conditions for any service of a Phase II Utility, as defined in § 56-585.1, shall be conducted at any time by the State Corporation Commission for the five successive 12-month test periods beginning January 1, 2015, and ending December 31, 2019. Such test periods beginning January 1, 2014, and ending December 31, 2017, for a Phase I Utility, and beginning January 1, 2015, and ending December 31, 2019, for a Phase II Utility, are collectively referred to herein as the "Transitional Rate Period." Review of recovery of fuel and purchase power costs shall continue during the Transitional Rate Period in accordance with § 56-249.6. Any biennial review of the rates, terms, and conditions for any service of a Phase II Utility occurring in 2015 during the Transitional Rate Period shall be solely a review of the utility's earnings on its rates for generation and distribution services for the two 12-month test periods ending December 31, 2014, and a determination of whether any credits to customers are due for such test periods pursuant to subdivision A 8 b of § 56-585.1. After the conclusion of the Transitional Rate Period, biennial reviews shall resume for a Phase I Utility in 2020, with the first such proceeding utilizing the two successive 12-month test periods beginning January 1, 2018, and ending December 31, 2019. After the conclusion of the Transitional Rate Period, biennial reviews shall resume for a Phase II Utility, as defined in § 56-585.1, in 2022, with the first such proceeding utilizing the two successive 12-month test periods beginning January 1, 2020, and ending December 31, 2021. Consistent with this provision, (i) no biennial review filings shall be made by an investor-owned incumbent electric utility in the years 2016 through 2019, inclusive, and (ii) no adjustment to an investor-owned incumbent electric utility's existing tariff rates, including any rates adopted pursuant to § 56-235.2, shall be made between the beginning of the Transitional Rate Period and the conclusion of the first biennial review after the conclusion of the Transitional Rate Period, except as may be provided pursuant to § 56-245 or 56-249.6 or subdivisions A 4, 5, or 6 of § 56-585.1.

B. During the Transitional Rate Period, pursuant to § 56-36, the Commission shall have the right at all times to inspect the books, papers and documents of any investor-owned incumbent electric utility and to require from such companies, from time to time, special reports and statements, under oath, concerning their business.

C. 1. Commencing in 2016 and concluding in 2018, the State Corporation Commission, after notice and opportunity for a hearing, shall conduct a proceeding every two years to determine the fair rate of return on common equity to be used by a Phase I Utility as the general rate of return applicable to rate adjustment clauses under subdivisions A 5 or A 6 of § 56-585.1. A Phase I Utility's filing in such proceedings shall be made on or before March 31 of 2016, and 2018.

2. Commencing in 2017 and concluding in 2019, the State Corporation Commission, after notice and opportunity for a hearing, shall conduct a proceeding every two years to determine the fair rate of return on common equity to be used by a Phase II Utility as the general rate of return applicable to rate adjustment clauses under subdivisions A 5 or A 6 of § 56-585.1. A Phase II utility's filing in such proceedings shall be made on or before March 31 of 2017 and 2019.

3. Such fair rate of return shall be calculated pursuant to the methodology set forth in subdivisions A 2 a and b of § 56-585.1 and shall utilize the utility's actual end-of-test-period capital structure and cost of capital, as well as a 12-month test period ending December 31 immediately preceding the year in which the proceeding is conducted. The Commission's final order in such a proceeding shall be entered no later than eight months after the date of filing, with any adjustment to the fair rate of return for applicable rate adjustment clauses under subdivisions A 5 and 6 of § 56-585.1 taking effect on the date of the Commission's final order in the proceeding, utilizing rate adjustment clause true-up protocols as the Commission may in its discretion determine. Such proceeding shall concern only the issue of the determination of such fair rate of return to be used for rate adjustment clauses under subdivisions A 5 and 6 of § 56-585.1, and such determination shall have no effect on rates other than those applicable to such rate adjustment clauses; however, after the final such proceeding for a utility has been concluded, the fair combined rate of return on common equity so determined therein shall also be deemed equal to the fair combined rate of return on common equity to be used in such utility's first biennial review proceeding conducted after the end of the utility's Transitional Rate Period to review such utility's earnings on its rates for generation and distribution services for the historic test periods.

D. In furtherance of rate stability during the Transitional Rate Period, any Phase II Utility carrying a prior period deferred fuel expense recovery balance on its books and records as of December 31, 2014, shall not recover from customers 50 percent of any such balance outstanding as of December 31, 2014, and the State Corporation Commission shall implement as soon as practicable reductions in the fuel factor rate of any such Phase II Utility to reflect the nonrecovery of any such fuel expense as well as any reduction in the fuel factor associated with the Phase II Utility's current period forecasted fuel expense over recovery for the 2014-2015 fuel year and projected fuel expense for the 2015-2016 fuel year.

E. Except for early retirement plans identified by the utility in an integrated resource plan filed with the State Corporation Commission by September 1, 2014, for utility generation plants, an investor-owned incumbent electric utility shall not permanently retire an electric power generation facility from service during the Transitional Rate Period without first obtaining the approval of the State Corporation Commission, upon petition from such investor-owned incumbent electric utility, and a finding by the State Corporation Commission that the retirement determination is reasonable and prudent. During the Transitional Rate Period, an investor-owned incumbent electric utility shall recover the following costs, as recorded per books by the utility for financial reporting purposes and accrued against income, only through its existing tariff rates for generation or distribution services, except such costs as may be recovered pursuant to § 56-245, § 56-249.6 or subdivisions A 4, A 5, or A 6 of § 56-585.1: (i) costs associated with asset impairments related to early retirement determinations for utility generation facilities resulting from the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to § 111(d) of the Clean Air Act; (ii) costs associated with severe weather events; and (iii) costs associated with natural disasters.

F. During the Transitional Rate Period:

1. The State Corporation Commission shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year assessing the updated integrated resource plan of any investor-owned incumbent electric utility. The report shall include an analysis of, among other matters, the amount, reliability, and type of generation facilities needed to serve Virginia native load compared to what is then available to serve such load and what may be available to serve such load in the future in view of market conditions and current and pending state and federal environmental regulations. As a part of such report, the State Corporation Commission shall update its estimate of the impact upon electric rates in Virginia of the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to § 111(d) of the federal Clean Air Act. The State Corporation Commission shall submit copies of such annual reports to the Chairmen of the House and Senate Committees on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation; and

2. The Department of Environmental Quality shall submit a report and make recommendations to the Governor and the General Assembly annually on or before December 1 of each year concerning the implementation of carbon emission guidelines for existing electric power generation facilities that the U.S. Environmental Protection Agency has issued pursuant to § 111(d) of the federal Clean Air Act. The report shall include an analysis of, among other matters, the impact of such federal regulations on the operation of any investor-owned incumbent electric utility's electric power generation facilities and any changes, interdiction, or suspension of such regulations. The Department of Environmental Quality shall submit copies of such annual reports to the Chairmen of the House and Senate Committees on Commerce and Labor and the Chairman of the Commission on Electric Utility Regulation.

G. The construction or purchase by an investor-owned incumbent utility of one or more generation facilities with at least one megawatt of generating capacity, and with an aggregate rated capacity that does not exceed 500 megawatts, that use energy derived from sunlight and are located in the Commonwealth, regardless of whether any of such facilities are located within or without such utility's service territory, is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this section. Such utility shall utilize goods or services sourced, in whole or in part, from one or more Virginia businesses. The utility may propose a rate adjustment clause based on a market index in lieu of a cost of service model for such facility. An investor-owned incumbent utility may enter into short-term or long-term power purchase contracts for the power derived from sunlight generated by such generation facility prior to purchasing the generation facility.

2015, c. 6.

§ 56-585.1:2. Pilot program for energy assistance and weatherization.

Notwithstanding the provisions of §§ 56-249.6 and 56-585.1:

Each Phase I and II Utility shall conduct a pilot program for energy assistance and weatherization for low income, elderly, and disabled individuals in their respective service territories in the Commonwealth. Each pilot program shall be funded by the utility and shall commence September 1, 2015. Each such utility shall report on the status of its pilot program, including the number of individuals served thereby, to the Governor, the State Corporation Commission, and the Chairmen of the House and Senate Commerce and Labor Committees by July 1, 2016, and each year thereafter.

2015, c. 6.

§ 56-585.1:3. Pilot programs for community solar development.

A. As used in this section:

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

1. Exclusively uses energy derived from sunlight;

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

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

4. Has a generating capacity of:

a. Not more than two megawatts; or

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

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

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

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

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

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

"Phase I Utility" means an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

b. Each RFP shall:

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

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

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

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

e. In selecting eligible generating facilities for dedication to its pilot program, an investor-owned utility shall give due consideration to relative costs, economic development benefits, and geographic diversity of eligible generating facilities.

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

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

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

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

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

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

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

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

6. Each pilot program shall expire at the end of its pilot program period, unless renewed or made permanent by appropriate legislation.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2017, c. 580.

§ 56-585.2. Sale of electricity from renewable sources through a renewable energy portfolio standard program.

A. As used in this section:

"Qualified investment" means an expense incurred in the Commonwealth by a participating utility in conducting, either by itself or in partnership with institutions of higher education in the Commonwealth or with industrial or commercial customers that have established renewable energy research and development programs in the Commonwealth, research and development activities related to renewable or alternative energy sources, which expense (i) is designed to enhance the participating utility's understanding of emerging energy technologies and their potential impact on and value to the utility's system and customers within the Commonwealth; (ii) promotes economic development within the Commonwealth; (iii) supplements customer-driven alternative energy or energy efficiency initiatives; (iv) supplements alternative energy and energy efficiency initiatives at state or local governmental facilities in the Commonwealth; or (v) is designed to mitigate the environmental impacts of renewable energy projects.

"Renewable energy" shall have the same meaning ascribed to it in § 56-576, provided such renewable energy is (i) generated in the Commonwealth or in the interconnection region of the regional transmission entity of which the participating utility is a member, as it may change from time to time, and purchased by a participating utility under a power purchase agreement; provided, however, that if such agreement was executed on or after July 1, 2013, the agreement shall expressly transfer ownership of renewable attributes, in addition to ownership of the energy, to the participating utility; (ii) generated by a public utility providing electric service in the Commonwealth from a facility in which the public utility owns at least a 49 percent interest and that is located in the Commonwealth, in the interconnection region of the regional transmission entity of which the participating utility is a member, or in a control area adjacent to such interconnection region; or (iii) represented by renewable energy certificates. "Renewable energy" shall not include electricity generated from pumped storage, but shall include run-of-river generation from a combined pumped-storage and run-of-river facility.

"Renewable energy certificate" means either (i) a certificate issued by an affiliate of the regional transmission entity of which the participating utility is a member, as it may change from time to time, or any successor to such affiliate, and held or acquired by such utility, that validates the generation of renewable energy by eligible sources in the interconnection region of the regional transmission entity or (ii) a certificate issued by the Commission pursuant to subsection J and held or acquired by a participating utility, that validates a qualified investment made by the participating utility.

"Total electric energy sold in the base year" means total electric energy sold to Virginia jurisdictional retail customers by a participating utility in calendar year 2007, excluding an amount equivalent to the average of the annual percentages of the electric energy that was supplied to such customers from nuclear generating plants for the calendar years 2004 through 2006.

B. Any investor-owned incumbent electric utility may apply to the Commission for approval to participate in a renewable energy portfolio standard program, as defined in this section. The Commission shall approve such application if the applicant demonstrates that it has a reasonable expectation of achieving 12 percent of its base year electric energy sales from renewable energy sources during calendar year 2022, and 15 percent of its base year electric energy sales from renewable energy sources during calendar year 2025, as provided in subsection D.

C. It is in the public interest for utilities that seek to have a renewable energy portfolio standard program to achieve the goals set forth in subsection D, such goals being referred to herein as "RPS Goals." A utility shall receive double credit toward meeting the renewable energy portfolio standard for energy derived from sunlight, from onshore wind, or from facilities in the Commonwealth fueled primarily by animal waste, and triple credit toward meeting the renewable energy portfolio standard for energy derived from offshore wind.

D. Regarding any renewable energy portfolio standard program, the total electric energy sold by a utility to meet the RPS Goals shall be composed of the following amounts of electric energy or renewable thermal energy equivalent from renewable energy sources, as adjusted for any sales volumes lost through operation of the customer choice provisions of subdivision A 3 or A 4 of § 56-577:

RPS Goal I: In calendar year 2010, 4 percent of total electric energy sold in the base year.

RPS Goal II: For calendar years 2011 through 2015, inclusive, an average of 4 percent of total electric energy sold in the base year, and in calendar year 2016, 7 percent of total electric energy sold in the base year.

RPS Goal III: For calendar years 2017 through 2021, inclusive, an average of 7 percent of total electric energy sold in the base year, and in calendar year 2022, 12 percent of total electric energy sold in the base year.

RPS Goal IV: For calendar years 2023 and 2024, inclusive, an average of 12 percent of total electric energy sold in the base year, and in calendar year 2025, 15 percent of total electric energy sold in the base year.

A utility may not apply renewable energy certificates issued pursuant to subsection J to meet more than 20 percent of the sales requirement for the RPS Goal in any year.

A utility may apply renewable energy sales achieved or renewable energy certificates acquired during the periods covered by any such RPS Goal that are in excess of the sales requirement for that RPS Goal to the sales requirements for any future RPS Goals in the five calendar years after the renewable energy was generated or the renewable energy certificates were created, except that a utility shall be able to apply renewable energy certificates acquired by the utility prior to January 1, 2014.

E. A utility participating in such program shall have the right to recover all incremental costs incurred for the purpose of such participation in such program, as accrued against income, through rate adjustment clauses as provided in subdivisions A 5 and A 6 of § 56-585.1, including, but not limited to, administrative costs, ancillary costs, capacity costs, costs of energy represented by certificates described in subsection A, and, in the case of construction of renewable energy generation facilities, allowance for funds used during construction until such time as an enhanced rate of return, as determined pursuant to subdivision A 6 of § 56-585.1, on construction work in progress is included in rates, projected construction work in progress, planning, development and construction costs, life-cycle costs, and costs of infrastructure associated therewith, plus an enhanced rate of return, as determined pursuant to subdivision A 6 of § 56-585.1. This subsection shall not apply to qualified investments as provided in subsection K. All incremental costs of the RPS program shall be allocated to and recovered from the utility's customer classes based on the demand created by the class and within the class based on energy used by the individual customer in the class, except that the incremental costs of the RPS program shall not be allocated to or recovered from customers that are served within the large industrial rate classes of the participating utilities and that are served at primary or transmission voltage.

F. A utility participating in such program shall apply towards meeting its RPS Goals any renewable energy from existing renewable energy sources owned by the participating utility or purchased as allowed by contract at no additional cost to customers to the extent feasible. A utility participating in such program shall not apply towards meeting its RPS Goals renewable energy certificates attributable to any renewable energy generated at a renewable energy generation source in operation as of July 1, 2007, that is operated by a person that is served within a utility's large industrial rate class and that is served at primary or transmission voltage, except for those persons providing renewable thermal energy equivalents to the utility. A participating utility shall be required to fulfill any remaining deficit needed to fulfill its RPS Goals from new renewable energy supplies at reasonable cost and in a prudent manner to be determined by the Commission at the time of approval of any application made pursuant to subsection B. A participating utility may sell renewable energy certificates produced at its own generation facilities located in the Commonwealth or, if located outside the Commonwealth, owned by such utility and in operation as of January 1, 2010, or renewable energy certificates acquired as part of a purchase power agreement, to another entity and purchase lower cost renewable energy certificates and the net difference in price between the renewable energy certificates shall be credited to customers. Utilities participating in such program shall collectively, either through the installation of new generating facilities, through retrofit of existing facilities or through purchases of electricity from new facilities located in Virginia, use or cause to be used no more than a total of 1.5 million tons per year of green wood chips, bark, sawdust, a tree or any portion of a tree which is used or can be used for lumber and pulp manufacturing by facilities located in Virginia, towards meeting RPS goals, excluding such fuel used at electric generating facilities using wood as fuel prior to January 1, 2007. A utility with an approved application shall be allocated a portion of the 1.5 million tons per year in proportion to its share of the total electric energy sold in the base year, as defined in subsection A, for all utilities participating in the RPS program. A utility may use in meeting RPS goals, without limitation, the following sustainable biomass and biomass based waste to energy resources: mill residue, except wood chips, sawdust and bark; pre-commercial soft wood thinning; slash; logging and construction debris; brush; yard waste; shipping crates; dunnage; non-merchantable waste paper; landscape or right-of-way tree trimmings; agricultural and vineyard materials; grain; legumes; sugar; and gas produced from the anaerobic decomposition of animal waste.

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

H. Each investor-owned incumbent electric utility shall report to the Commission annually by November 1 identifying:

1. The utility's efforts, if any, to meet the RPS Goals, specifically identifying:

a. A list of all states where the purchased or owned renewable energy was generated, specifying the number of megawatt hours or renewable energy certificates originating from each state;

b. A list of the decades in which the purchased or owned renewable energy generating units were placed in service, specifying the number of megawatt hours or renewable energy certificates originating from those units; and

c. A list of fuel types used to generate the purchased or owned renewable energy, specifying the number of megawatt hours or renewable energy certificates originating from each fuel type;

2. The utility's overall generation of renewable energy; and

3. Advances in renewable generation technology that affect activities described in subdivisions 1 and 2.

I. The Commission shall post on its website the reports submitted by each investor-owned incumbent electric utility pursuant to subsection H.

J. The Commission shall issue to a participating utility a number of renewable energy certificates for qualified investments, upon request by a participating utility, if it finds that an expense satisfies the conditions set forth in this section for a qualified investment, as follows:

1. By March 31 of each year, the participating utility shall provide an analysis, as reasonably determined by a qualified independent broker, of the average for the preceding year of the publicly available prices for Tier 1 renewable energy certificates and Tier 2 renewable energy certificates, validating the generation of renewable energy by eligible sources, that were issued in the interconnection region of the regional transmission entity of which the participating utility is a member;

2. In the same annual analysis provided to the Commission, the participating utility shall divide the amount of the participating utility's qualified investments in the applicable period by the average price determined pursuant to subdivision 1;

3. The number of renewable energy certificates to be issued to the participating utility shall equal the product obtained pursuant to subdivision 2; and

4. The Commission shall review and validate the analysis provided by the participating utility within 90 days of submittal of its analysis to the Commission. If no corrections are made by the Commission, then the analysis shall be deemed correct and the renewable energy certificates shall be deemed issued to the participating utility.

Each renewable energy certificate issued to a participating utility pursuant to this subsection shall represent the equivalent of one megawatt hour of renewable energy sales achieved when applied to an RPS Goal.

K. Qualified investments shall constitute reasonable and prudent operating expenses of a participating utility. Notwithstanding subsection E, a participating utility shall not be authorized to recover the costs associated with qualified investments through rate adjustment clauses as provided in subdivisions A 5 and A 6 of § 56-585.1. In any proceeding conducted pursuant to § 56-585.1 or other provision of this title in which a participating utility seeks recovery of its qualified investments as an operating expense, the participating utility shall not be authorized to earn a return on its qualified investments.

L. A participating utility shall not be eligible for a research and development tax credit pursuant to § 58.1-439.12:08 or 58.1-439.12:11 with regard to any expense incurred or investment made by the participating utility that constitutes a qualified investment pursuant to this section.

2007, cc. 888, 933; 2008, c. 651; 2009, c. 744; 2010, c. 850; 2012, cc. 46, 67, 200, 274, 348, 717; 2013, cc. 2, 308, 403; 2014, cc. 420, 465; 2016, cc. 300, 661.

§ 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 of this title shall be regulated in accordance with the provisions of Chapters 9.1 (§ 56-231.15 et seq.) and 10 (§ 56-232 et seq.) of this title, 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 5 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; 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. 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; and

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

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

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

2007, cc. 888, 933; 2009, cc. 401, 824.

§ 56-586. Emergency service provider.

On and after January 1, 2001, if any supplier fails to fulfill an obligation, resulting in the failure of retail electric energy to be delivered into the control area serving the supplier's retail customer, the entity fulfilling the control area function, or, if applicable, the regional transmission entity or other entity as designated by the Commission, shall be responsible for charging the defaulting supplier for the full cost of replacement energy, including the cost of energy, the cost incurred by others as a result of the default, and the assessment of penalties as may be approved either by the Commission, to the extent not precluded by federal law, or by the Federal Energy Regulatory Commission. The Commission, as part of the rules established under § 56-587, shall determine the circumstances under which failures to deliver electricity will result in the revocation of the supplier's license.

1999, c. 411.

§ 56-586.1. Electric energy emergencies.

A. As used in this section, "electric energy emergency" means an unplanned interruption in the generation or transmission of electricity resulting from a hurricane, ice storm, windstorm, earthquake or similar natural phenomena, or from a criminal act affecting such generation or transmission, act of war or act of terrorism, which interruption is (i) of such severity that minimum levels of reliable service cannot be maintained using resources practicably obtainable from the market and (ii) so imminently and substantially threatening to the health, safety or welfare of residents of this Commonwealth that immediate action of state government is necessary to prevent loss of life, protect the public health or safety, and prevent unnecessary or avoidable damage to property.

B. The Governor is authorized, after finding that an electric energy emergency exists and that appropriate federal and state agencies and appropriate reliability councils cannot adequately address such emergency, to declare an electric energy emergency by filing a written declaration with the Secretary of the Commonwealth. The declaration shall state the counties and cities or utility service areas of the Commonwealth in which the declaration is applicable, or its statewide application. A declared electric energy emergency shall go into immediate effect upon filing and continue in effect for the period prescribed in the declaration, but not more than thirty days. At the end of the prescribed period, the Governor may issue another declaration extending the emergency. The Governor shall terminate such declaration as soon as the basis for such declaration no longer exists.

C. During a declared electric energy emergency, the Governor is authorized, in compliance with guidelines of the Department of Emergency Services promulgated as provided in subsection G, to require any generator or any municipal electric utility that is capable of generating but (i) is not generating or (ii) is not generating at its full potential during such declared electric emergency, to generate, dispatch or sell electricity from a facility that it operates within the Commonwealth, to the Commonwealth for distribution within the areas of the Commonwealth designated in the declaration. The quantity of electricity required to be generated, dispatched or sold, and the duration of such requirements, shall be as determined by the Governor to be necessary to alleviate the electric energy emergency hardship. The Commonwealth shall compensate an entity required to generate, dispatch, or sell electricity pursuant to this subsection, and the operator of any transmission facilities over which the electricity is transmitted, in the manner provided in § 56-522, mutatis mutandis, unless otherwise provided by federal law. The Department of Environmental Quality, the State Air Pollution Control Board, the State Water Control Board, and the Virginia Waste Management Board shall issue any temporary or emergency permit, order, or variance necessary to authorize any permit amendments or other changes needed to meet the requirements imposed under this section and the Governor may petition the President to declare a regional energy emergency under 42 U.S.C. § 7410 (f) as necessary to suspend enforcement of any provision of the federal Clean Air Act. Any increased operation required during such declared emergency shall not be counted towards the number of hours of operation allowed during the year. No civil charges or penalties shall be imposed for any violation that occurs as a result of actions taken that are necessary for the required generation, dispatch or sale during the declared electric energy emergency. The foregoing provisions shall apply to all actions the entity takes in connection with such required generation, dispatch or sale during the period of the declared emergency.

D. During a declared electric energy emergency, the Governor may use the services, equipment, supplies, and facilities of existing departments, offices, and agencies of the Commonwealth, and of the political subdivisions thereof, to the maximum extent practicable and necessary to meet the electric energy emergency. The officers and personnel of all such departments, offices, and agencies shall cooperate with and extend such services and facilities to the Governor upon request.

E. During a declared electric energy emergency, the Governor is authorized to request the Secretary of the United States Department of Energy to invoke section 202(C) of the Federal Power Act, 16 U.S.C. § 824a (1935).

F. The General Assembly is authorized by joint resolution to terminate any declaration of an electric energy emergency. The emergency shall be terminated at the time of filing of the joint resolution with the Secretary of the Commonwealth.

G. The Department of Emergency Services, in consultation with the Commission and the Secretary of Commerce and Trade, shall establish guidelines for the implementation of the Governor's powers pursuant to subsection C that protect the public health and safety and prevent unnecessary or avoidable damage to property with a minimum of economic disruption to generators, transmitters and distributors of electricity. Such guidelines shall:

1. Define various foreseeable levels of electric energy emergencies and specify appropriate measures to be taken for each type of electric energy emergency as necessary to protect the public health or safety or prevent unnecessary or avoidable damage to property;

2. Prescribe appropriate response measures for each level of electric energy emergency; and

3. Equitably distribute the burdens and benefits resulting from the implementation of this section among other members of the affected class of persons within all geographic regions of the Commonwealth.

H. During a declared electric energy emergency, the attorney general may bring an action for injunctive or other appropriate relief in the Circuit Court of the City of Richmond to secure prompt compliance. The court may issue an ex parte temporary order without notice that shall enforce the prohibitions, restrictions or actions that are necessary to secure compliance with the guideline, order or declaration.

I. During a declared electric energy emergency, no person shall intentionally violate any guideline adopted or declaration issued pursuant to this section. Any person who violates this section is guilty of a Class 1 misdemeanor.

2002, c. 609.

§ 56-587. Licensure of retail electric energy suppliers and persons providing other competitive services.

A. As a condition of doing business in the Commonwealth, each person except a default service provider seeking to sell, offering to sell, or selling electric energy to any retail customer in the Commonwealth, on and after January 1, 2002, shall obtain a license from the Commission to do so. A license shall not be required solely for the leasing or financing of property used in the sale of electricity to any retail customer in the Commonwealth.

The license shall authorize that person to engage in the activities authorized by such license until the license expires or is otherwise terminated, suspended or revoked.

B. 1. As a condition of obtaining, retaining and renewing any license issued pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, which may include requirements that such person (i) demonstrate, in a manner satisfactory to the Commission, financial responsibility; (ii) post a bond as deemed adequate by the Commission to ensure that financial responsibility; (iii) pay an annual license fee to be determined by the Commission; and (iv) pay all taxes and fees lawfully imposed by the Commonwealth or by any municipality or other political subdivision of the Commonwealth. In addition, as a condition of obtaining, retaining and renewing any license pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, including but not limited to requirements that such person demonstrate (i) technical capabilities as the Commission may deem appropriate; (ii) in the case of a person seeking to sell, offering to sell, or selling electric energy to any retail customer in the Commonwealth, access to generation and generation reserves; and (iii) adherence to minimum market conduct standards.

2. Any license issued by the Commission pursuant to this section to a person seeking to sell, offering to sell, or selling electric energy to any retail customer in the Commonwealth may be conditioned upon the licensee furnishing to the Commission prior to the provision of electric energy to consumers proof of adequate access to generation and generation reserves.

C. 1. The Commission shall establish a reasonable period within which any retail customer may cancel, without penalty or cost, any contract entered into with any person licensed pursuant to this section.

2. The Commission may adopt other rules and regulations governing the requirements for obtaining, retaining, and renewing a license issued pursuant to this section, and may, as appropriate, refuse to issue a license to, or suspend, revoke, or refuse to renew the license of, any person that does not meet those requirements.

D. Notwithstanding the provisions of § 13.1-620, a public service company may, through an affiliate or subsidiary, conduct one or more of the following businesses, even if such business is not related to or incidental to its stated business as a public service company: (i) become licensed as a retail electric energy supplier pursuant to this section, or for purposes of participation in an approved pilot program encompassing retail customer choice of electric energy suppliers; (ii) become licensed as an aggregator pursuant to § 56-588, or for purposes of participation in an approved pilot program encompassing retail customer choice of electric energy suppliers; or (iii) own, manage or control any plant or equipment or any part of a plant or equipment used for the generation of electric energy.

1999, c. 411; 2000, c. 991; 2007, cc. 888, 933.

§ 56-588. Licensing of aggregators.

A. As a condition of doing business in the Commonwealth, each person seeking to act as an aggregator within this Commonwealth on and after January 1, 2002, shall obtain a license from the Commission to do so. The license shall authorize that person to act as an aggregator until the license expires or is otherwise terminated, suspended or revoked. Licensing pursuant to this section, however, shall not relieve any person seeking to act as a supplier of electric energy from their obligation to obtain a license as a supplier pursuant to § 56-587.

B. As a condition of obtaining, retaining and renewing any license issued pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, which may include requirements that such person (i) provide background information; (ii) demonstrate, in a manner satisfactory to the Commission, financial responsibility; (iii) post a bond as deemed adequate by the Commission to ensure that financial responsibility; (iv) pay an annual license fee to be determined by the Commission; and (v) pay all taxes and fees lawfully imposed by the Commonwealth or by any municipality or other political subdivision of the Commonwealth. In addition, as a condition of obtaining, retaining and renewing any license pursuant to this section, a person shall satisfy such reasonable and nondiscriminatory requirements as may be specified by the Commission, including, but not limited to, requirements that such person demonstrate technical capabilities as the Commission may deem appropriate. Any license issued by the Commission pursuant to this section may be conditioned upon the licensee, if acting as a supplier, furnishing to the Commission prior to the provision of electricity to consumers proof of adequate access to generation and generation reserves.

C. In establishing aggregator licensing schemes and requirements applicable to the same, the Commission may differentiate between (i) those aggregators representing retail customers only, (ii) those aggregators representing suppliers only, and (iii) those aggregators representing both retail customers and suppliers.

D. 1. The Commission shall establish a reasonable period within which any retail customer may cancel, without penalty or cost, any contract entered into with an aggregator licensed pursuant to this section.

2. The Commission may adopt other rules and regulations governing the requirements for obtaining, retaining, and renewing a license to aggregate electric energy to retail customers, and may, as appropriate, refuse to issue a license to, or suspend, revoke, or refuse to renew the license of, any person that does not meet those requirements.

1999, c. 411; 2000, c. 991.

§ 56-589. Municipal and state aggregation.

A. Subject to the provisions of subdivision A 3 of § 56-577, counties, cities, and towns (hereafter municipalities) and other political subdivisions of the Commonwealth may, at their election and upon authorization by majority votes of their governing bodies, aggregate electrical energy and demand requirements for the purpose of negotiating the purchase of electrical energy requirements from any licensed supplier within this Commonwealth, as follows:

1. Any municipality or other political subdivision of the Commonwealth may aggregate the electric energy load of residential, commercial, and industrial retail customers within its boundaries on an opt-in or opt-out basis.

2. Any municipality or other political subdivision of the Commonwealth may aggregate the electric energy load of its governmental buildings, facilities, and any other governmental operations requiring the consumption of electric energy. Aggregation pursuant to this subdivision shall not require licensure pursuant to § 56-588.

3. Two or more municipalities or other political subdivisions within the Commonwealth may aggregate the electric energy load of their governmental buildings, facilities, and any other governmental operations requiring the consumption of electric energy. Aggregation pursuant to this subdivision shall not require licensure pursuant to § 56-588 when such municipalities or other political subdivisions are acting jointly to negotiate or arrange for themselves agreements for their energy needs directly with licensed suppliers or aggregators.

Nothing in this subsection shall prohibit the Commission's development and implementation of pilot programs for opt-in, opt-out, or any other type of municipal aggregation, as provided in § 56-577.

B. The Commonwealth, at its election, may aggregate the electric energy load of its governmental buildings, facilities, and any other government operations requiring the consumption of electric energy for the purpose of negotiating the purchase of electricity from any licensed supplier within the Commonwealth. Aggregation pursuant to this subsection shall not require licensure pursuant to § 56-588.

C. Nothing in this section shall preclude municipalities from aggregating the electric energy load of their governmental buildings, facilities and any other governmental operations requiring the consumption of electric energy for the purpose of negotiating rates and terms, and conditions of service from the electric utility certificated by the Commission to serve the territory in which such buildings, facilities and operations are located, provided, however, that no such electric energy load shall be aggregated for this purpose unless all such buildings, facilities and operations to be aggregated are served by the same electric utility.

1999, c. 411; 2000, c. 991; 2003, c. 795; 2004, c. 827; 2007, cc. 888, 933.

§ 56-590. Divestiture, functional separation and other corporate relationships.

A. The Commission shall not require any incumbent electric utility to divest itself of any generation, transmission or distribution assets pursuant to any provision of this chapter.

B. 1. The Commission shall, however, direct the functional separation of generation, retail transmission and distribution of all incumbent electric utilities in connection with the provisions of this chapter to be completed by January 1, 2002.

2. By January 1, 2001, each incumbent electric utility shall submit to the Commission a plan for such functional separation which may be accomplished through the creation of affiliates, or through such other means as may be acceptable to the Commission.

3. Consistent with this chapter, the Commission may impose conditions, as the public interest requires, upon its approval of any incumbent electric utility's plan for functional separation, including requirements that (i) the incumbent electric utility's generation assets or, at the election of the incumbent electric utility and if approved by the Commission pursuant to subdivision 4 of this subsection, their equivalent are made available for electric service during the capped rate period as provided in § 56-582 and, if applicable, during any period the distributor serves as a default provider as provided for in § 56-585; (ii) the incumbent electric utility receive Commission approval for the sale, transfer or other disposition of generation assets during the capped rate period and, if applicable, during any period the distributor serves as a default provider; and (iii) any such generation asset sold, transferred, or otherwise disposed of by the incumbent electric utility with Commission approval shall not be further sold, transferred, or otherwise disposed of during the capped rate period and, if applicable, during any period the distributor serves as default provider, without additional Commission approval.

4. If an incumbent electric utility proposes that the equivalent to its generation assets be made available pursuant to subdivision 3 of this subsection, the Commission shall determine the adequacy of such proposal and shall approve or reject such proposal based on the public interest.

5. In exercising its authority under the provisions of this section and under § 56-90, the Commission shall have no authority to regulate, on a cost-of-service basis or other basis, the price at which generation assets or their equivalent are made available for default service purposes. Such restriction on the Commission's authority to regulate, on a cost-of-service basis or other basis, prices for default service shall not affect the ability of a distributor to offer to provide, and of the Commission to approve if appropriate the provision of, such services on a cost plus basis or any other basis. The Commission's authority to regulate the price of default service shall be consistent with the pricing provisions applicable to a distributor pursuant to § 56-585. In addition, the Commission shall, in exercising its responsibilities under this section and under § 56-90, consider, among other factors, the potential effects of any such transfer on: (i) rates and reliability of capped rate service under § 56-582, and of default service under § 56-585, and (ii) the development of a competitive market in the Commonwealth for retail generation services. However, the Commission may not deny approval of a transfer proposed by an incumbent electric utility, pursuant to subdivisions 2 and 4 of this subsection, due to an inability to determine, at the time of consideration of the transfer, default service prices under § 56-585.

C. The Commission shall, to the extent necessary to promote effective competition in the Commonwealth, promulgate rules and regulations to carry out the provisions of this section, which rules and regulations shall include provisions:

1. Prohibiting cost-shifting or cross-subsidies between functionally separate units;

2. Prohibiting functionally separate units from engaging in anticompetitive behavior or self-dealing;

3. Prohibiting affiliated entities from engaging in discriminatory behavior towards nonaffiliated units; and

4. Establishing codes of conduct detailing permissible relations between functionally separate units.

D. Neither a covered entity nor an affiliate thereof may be a party to a covered transaction without the prior approval of the Commission. Any such person proposing to be a party to such transaction shall file an application with the Commission. The Commission shall approve or disapprove such transaction within sixty days after the filing of a completed application; however, the sixty-day period may be extended by Commission order for a period not to exceed an additional 120 days. The application shall be deemed approved if the Commission fails to act within such initial or extended period. The Commission shall approve such application if it finds, after notice and opportunity for hearing, that the transaction will comply with the requirements of subsection E, and may, as a part of its approval, establish such conditions or limitations on such transaction as it finds necessary to ensure compliance with subsection E.

E. A transaction described in subsection D shall not:

1. Substantially lessen competition among the actual or prospective providers of noncompetitive electric service or of a service which is, or is likely to become, a competitive electric service; or

2. Jeopardize or impair the safety or reliability of electric service in the Commonwealth, or the provision of any noncompetitive electric service at just and reasonable rates.

F. Except as provided in subdivision B 5, nothing in this chapter shall be deemed to abrogate or modify the Commission's authority under Chapter 3 (§ 56-55 et seq.), 4 (§ 56-76 et seq.) or 5 (§ 56-88 et seq.) of this title. However, any person subject to the requirements of subsection D that is also subject to the requirements of Chapter 5 of this title may be exempted from compliance with the requirements of Chapter 5 of this title.

1999, c. 411; 2000, c. 991; 2001, c. 748; 2007, cc. 888, 933.

§ 56-591. Application of antitrust laws.

Nothing in this chapter shall be construed to exempt or immunize from punishment or prosecution, conduct violative of federal antitrust laws, or the antitrust laws of this Commonwealth.

1999, c. 411.

§ 56-592. Consumer education and marketing practices.

A. The Commission shall develop an electric energy consumer education program designed to provide the following information to retail customers:

1. Information regarding energy conservation, energy efficiency, demand-side management, demand response, and renewable energy;

2. Information concerning demand-side management and demand response programs offered in the Commonwealth to retail customers;

3. Information regarding the matters described in subdivisions 1 and 2 that are specifically designed for the industrial, commercial, residential, and government sectors; and

4. Such other information as the Commission may deem necessary and appropriate in the public interest.

B. The Commission shall complete the development of the consumer education program described in subsection A, and report its findings and recommendations to the Commission on Electric Utility Regulation as frequently as may be required by such Commission concerning:

1. The scope of such recommended program consistent with the requirements of subsection A;

2. Materials and media required to effectuate any such program;

3. State agency and nongovernmental entity participation;

4. Program duration;

5. Funding requirements and mechanisms for any such program; and

6. Such other findings and recommendations the Commission deems appropriate in the public interest.

C. The Commission shall develop regulations governing marketing practices by public service companies, licensed suppliers, aggregators or any other providers of services made competitive by this chapter, including regulations to prevent unauthorized switching of suppliers, unauthorized charges, and improper solicitation activities. The Commission shall also establish standards for marketing information to be furnished by licensed suppliers, aggregators or any other providers of services made competitive by this chapter, which information shall include standards concerning:

1. Pricing and other key contract terms and conditions;

2. To the extent feasible, fuel mix and emissions data on at least an annualized basis;

3. Customer's rights of cancellation following execution of any contract;

4. Toll-free telephone number for customer assistance; and

5. Such other and further marketing information as the Commission may deem necessary and appropriate in the public interest.

D. The Commission shall also establish standards for billing information to be furnished by public service companies, suppliers, aggregators or any other providers of services made competitive by this chapter. Such billing information standards shall require that billing formation:

1. Distinguishes between charges for regulated services and unregulated services;

2. Is presented in a format that complies with standards to be established by the Commission;

3. Discloses, to the extent feasible, fuel mix and emissions data on at least an annualized basis; and

4. Includes such other billing information as the Commission deems necessary and appropriate in the public interest.

E. The Commission shall establish or maintain a complaint bureau for the purpose of receiving, reviewing and investigating complaints by retail customers against public service companies, licensed suppliers, aggregators and other providers of any services made competitive under this chapter. Upon the request of any interested person or the Attorney General, or upon its own motion, the Commission shall be authorized to inquire into possible violations of this chapter and to enjoin or punish any violations thereof pursuant to its authority under this chapter, this title, and under Title 12.1. The Attorney General shall have a right to participate in such proceedings consistent with the Commission's Rules of Practice and Procedure.

F. The Commission shall establish reasonable limits on customer security deposits required by public service companies, suppliers, aggregators or any other persons providing competitive services pursuant to this chapter.

1999, c. 411; 2003, c. 885; 2008, c. 883.

§ 56-592.1. Consumer education program; scope and funding.

A. The Commission shall establish and implement the consumer education program developed pursuant to subsection A of § 56-592. In establishing such a program, the Commission shall take into account the findings and recommendations of the subgroup on Information/Consumer Education that was established in conjunction with the Commission's proceeding in Case PUE-2007-00049, that implemented the third enactment of Chapters 888 and 933 of the Acts of Assembly of 2007.

B. The program shall be designed to (i) enable consumers to make rational and informed choices about the matters described in subsection A of § 56-592, including but not limited to demand side management, energy conservation, and energy efficiency, (ii) help consumers reduce transaction costs in making decisions regarding such matters, and (iii) foster compliance with the consumer protection provisions of this chapter.

C. The Commission shall regularly consult with representatives of consumer organizations, community-based groups, state agencies, incumbent utilities, and other interested parties throughout the program's implementation and operation.

D. Pursuant to the provisions of § 30-205, the Commission shall provide periodic updates to the Commission on Electric Utility Regulation concerning the program's implementation and operation.

E. The Commission shall fund the establishment and operation of such consumer education program through the special regulatory revenue tax currently authorized by § 58.1-2660 and the special regulatory tax authorized by Chapter 29 (§ 58.1-2900 et seq.) of Title 58.1.

2000, c. 991; 2003, c. 885; 2008, c. 883.

§ 56-593. Retail customers' private right of action; marketing practices.

A. No entity subject to this chapter shall use any deception, fraud, false pretense, misrepresentation, or any deceptive or unfair practices in providing, distributing or marketing electric service.

B. 1. Any person who suffers loss (i) as the result of marketing practices, including telemarketing practices, engaged in by any public service company, licensed supplier, aggregator or any other provider of any service made competitive under this chapter, and in violation of subsection C of § 56-592, including any rule or regulation adopted by the Commission pursuant thereto, or (ii) as the result of any violation of subsection A, shall be entitled to initiate an action to recover actual damages, or $500, whichever is greater. If the trier of fact finds that the violation was willful, it may increase damages to an amount not exceeding three times the actual damages sustained, or $1,000, whichever is greater.

2. Upon referral from the Commission, the Attorney General, the attorney for the Commonwealth, or the attorney for any city, county, or town may cause an action to be brought in the appropriate circuit court for relief of violations within the scope of (i) subsection C of § 56-592, including any rule or regulation adopted by the Commission pursuant thereto or (ii) subsection A.

C. Notwithstanding any other provision of law to the contrary, in addition to any damages awarded, such person, or any governmental agency initiating such action, also may be awarded reasonable attorney's fees and court costs.

D. Any action pursuant to this section shall be commenced within two years after its accrual. The cause of action shall accrue as provided in § 8.01-230. However, if the Commission initiates proceedings, or any other governmental agency files suit for the purpose of enforcing subsection A of this section or the provisions of subsection C of § 56-592, the time during which such proceeding or governmental suit and all appeals therefrom is pending shall not be counted as any part of the period within which an action under this section shall be brought.

E. The circuit court may make such additional orders or decrees as may be necessary to restore to any identifiable person any money or property, real, personal, or mixed, tangible or intangible, which may have been acquired from such person by means of any act or practice violative of subsection A of this section or subsection C of § 56-592, provided, that such person shall be identified by order of the court within 180 days from the date of any order permanently enjoining the unlawful act or practice.

F. In any case arising under this section, no liability shall be imposed upon any licensed supplier, aggregator or any other provider of any service made competitive under this chapter, who shows by a preponderance of the evidence that (i) the act or practice alleged to be in violation of subsection A of this section or subsection C of § 56-592 was an act or practice over which the same had no control or (ii) the alleged violation resulted from a bona fide error notwithstanding the maintenance of procedures reasonably adopted to avoid a violation. However, nothing in this section shall prevent the court from ordering restitution and payment of reasonable attorney's fees and court costs pursuant to subsection C to individuals aggrieved as a result of an unintentional violation of subsection A of this section or subsection C of § 56-592.

1999, c. 411; 2000, c. 991.

§ 56-594. Net energy metering provisions.

A. The Commission shall establish by regulation a program that affords eligible customer-generators the opportunity to participate in net energy metering, and a program, to begin no later than July 1, 2014, for customers of investor-owned utilities and no later than July 1, 2015, for customers of electric cooperatives, to afford eligible agricultural customer-generators the opportunity to participate in net energy metering. The regulations may include, but need not be limited to, requirements for (i) retail sellers; (ii) owners or operators of distribution or transmission facilities; (iii) providers of default service; (iv) eligible customer-generators; (v) eligible agricultural customer-generators; or (vi) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest. On and after July 1, 2017, small agricultural generators or eligible agricultural customer-generators may elect to interconnect pursuant to the provisions of this section or as small agricultural generators pursuant to § 56-594.2, but not both. Existing eligible agricultural customer-generators may elect to become small agricultural generators, but may not revert to being eligible agricultural customer-generators after such election. On and after July 1, 2019, interconnection of eligible agricultural customer-generators shall cease for electric cooperatives only, and such facilities shall interconnect solely as small agricultural generators. For electric cooperatives, eligible agricultural customer-generators whose renewable energy generating facilities were interconnected before July 1, 2019, may continue to participate in net energy metering pursuant to this section for a period not to exceed 25 years from the date of their renewable energy generating facility's original interconnection.

B. For the purpose of this section:

"Eligible agricultural customer-generator" means a customer that operates a renewable energy generating facility as part of an agricultural business, which generating facility (i) uses as its sole energy source solar power, wind power, or aerobic or anaerobic digester gas, (ii) does not have an aggregate generation capacity of more than 500 kilowatts, (iii) is located on land owned or controlled by the agricultural business, (iv) is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (v) is interconnected and operated in parallel with an electric company's transmission and distribution facilities, and (vi) is used primarily to provide energy to metered accounts of the agricultural business. An eligible agricultural customer-generator may be served by multiple meters that are located at separate but contiguous sites, such that the eligible agricultural customer-generator may aggregate in a single account the electricity consumption and generation measured by the meters, provided that the same utility serves all such meters. The aggregated load shall be served under the appropriate tariff.

"Eligible customer-generator" means a customer that owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility that (i) has a capacity of not more than 20 kilowatts for residential customers and not more than one megawatt for nonresidential customers on an electrical generating facility placed in service after July 1, 2015; (ii) uses as its total source of fuel renewable energy, as defined in § 56-576; (iii) is located on the customer's premises and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's own electricity requirements. In addition to the electrical generating facility size limitations in clause (i), the capacity of any generating facility installed under this section after July 1, 2015, shall not exceed the expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available.

"Net energy metering" means measuring the difference, over the net metering period, between (i) electricity supplied to an eligible customer-generator or eligible agricultural customer-generator from the electric grid and (ii) the electricity generated and fed back to the electric grid by the eligible customer-generator or eligible agricultural customer-generator.

"Net metering period" means the 12-month period following the date of final interconnection of the eligible customer-generator's or eligible agricultural customer-generator's system with an electric service provider, and each 12-month period thereafter.

"Small agricultural generator" has the same meaning that is ascribed to that term in § 56-594.2.

C. The Commission's regulations shall ensure that (i) the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions and (ii) any eligible customer-generator seeking to participate in net energy metering shall notify its supplier and receive approval to interconnect prior to installation of an electrical generating facility. The electric distribution company shall have 30 days from the date of notification for residential facilities, and 60 days from the date of notification for nonresidential facilities, to determine whether the interconnection requirements have been met. Such regulations shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system, and each electrical generating system of an eligible agricultural customer-generator, shall meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories. Beyond the requirements set forth in this section and to ensure public safety, power quality, and reliability of the supplier's electric distribution system, an eligible customer-generator or eligible agricultural customer-generator whose electrical generating system meets those standards and rules shall bear all reasonable costs of equipment required for the interconnection to the supplier's electric distribution system, including costs, if any, to (a) install additional controls, (b) perform or pay for additional tests, and (c) purchase additional liability insurance.

D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the eligible customer-generator or eligible agricultural customer-generator against discrimination by virtue of its status as an eligible customer-generator or eligible agricultural customer-generator, and permit customers that are served on time-of-use tariffs that have electricity supply demand charges contained within the electricity supply portion of the time-of-use tariffs to participate as an eligible customer-generator or eligible agricultural customer-generator. Notwithstanding the cost allocation provisions of subsection C, eligible customer-generators or eligible agricultural customer-generators served on demand charge-based time-of-use tariffs shall bear the incremental metering costs required to net meter such customers.

E. If electricity generated by an eligible customer-generator or eligible agricultural customer-generator over the net metering period exceeds the electricity consumed by the eligible customer-generator or eligible agricultural customer-generator, the customer-generator or eligible agricultural customer-generator shall be compensated for the excess electricity if the entity contracting to receive such electric energy and the eligible customer-generator or eligible agricultural customer-generator enter into a power purchase agreement for such excess electricity. Upon the written request of the eligible customer-generator or eligible agricultural customer-generator, the supplier that serves the eligible customer-generator or eligible agricultural customer-generator shall enter into a power purchase agreement with the requesting eligible customer-generator or eligible agricultural customer-generator that is consistent with the minimum requirements for contracts established by the Commission pursuant to subsection D. The power purchase agreement shall obligate the supplier to purchase such excess electricity at the rate that is provided for such purchases in a net metering standard contract or tariff approved by the Commission, unless the parties agree to a higher rate. The eligible customer-generator or eligible agricultural customer-generator owns any renewable energy certificates associated with its electrical generating facility; however, at the time that the eligible customer-generator or eligible agricultural customer-generator enters into a power purchase agreement with its supplier, the eligible customer-generator or eligible agricultural customer-generator shall have a one-time option to sell the renewable energy certificates associated with such electrical generating facility to its supplier and be compensated at an amount that is established by the Commission to reflect the value of such renewable energy certificates. Nothing in this section shall prevent the eligible customer-generator or eligible agricultural customer-generator and the supplier from voluntarily entering into an agreement for the sale and purchase of excess electricity or renewable energy certificates at mutually-agreed upon prices if the eligible customer-generator or eligible agricultural customer-generator does not exercise its option to sell its renewable energy certificates to its supplier at Commission-approved prices at the time that the eligible customer-generator or eligible agricultural customer-generator enters into a power purchase agreement with its supplier. All costs incurred by the supplier to purchase excess electricity and renewable energy certificates from eligible customer-generators or eligible agricultural customer-generators shall be recoverable through its Renewable Energy Portfolio Standard (RPS) rate adjustment clause, if the supplier has a Commission-approved RPS plan. If not, then all costs shall be recoverable through the supplier's fuel adjustment clause. For purposes of this section, "all costs" shall be defined as the rates paid to the eligible customer-generator or eligible agricultural customer-generator for the purchase of excess electricity and renewable energy certificates and any administrative costs incurred to manage the eligible customer-generator's or eligible agricultural customer-generator's power purchase arrangements. The net metering standard contract or tariff shall be available to eligible customer-generators or eligible agricultural customer-generators on a first-come, first-served basis in each electric distribution company's Virginia service area until the rated generating capacity owned and operated by eligible customer-generators, eligible agricultural customer-generators, and small agricultural generators in the state reaches one percent of each electric distribution company's adjusted Virginia peak-load forecast for the previous year, and shall require the supplier to pay the eligible customer-generator or eligible agricultural customer-generator for such excess electricity in a timely manner at a rate to be established by the Commission.

F. Any residential eligible customer-generator or eligible agricultural customer-generator who owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility with a capacity that exceeds 10 kilowatts shall pay to its supplier, in addition to any other charges authorized by law, a monthly standby charge. The amount of the standby charge and the terms and conditions under which it is assessed shall be in accordance with a methodology developed by the supplier and approved by the Commission. The Commission shall approve a supplier's proposed standby charge methodology if it finds that the standby charges collected from all such eligible customer-generators and eligible agricultural customer-generators allow the supplier to recover only the portion of the supplier's infrastructure costs that are properly associated with serving such eligible customer-generators or eligible agricultural customer-generators. Such an eligible customer-generator or eligible agricultural customer-generator shall not be liable for a standby charge until the date specified in an order of the Commission approving its supplier's methodology.

1999, c. 411; 2004, c. 827; 2006, c. 470; 2007, cc. 877, 888, 933; 2009, c. 804; 2011, c. 239; 2013, c. 268; 2015, cc. 431, 432; 2017, cc. 565, 581.

§ 56-594.1. Interconnection by farms.

A. As used in this section, "eligible farm" means an entity that owns or operates facilities within the Commonwealth for the generation of electric energy, which entity is described in subdivision (b)(10) of § 56-265.1.

B. Eligible farms shall be permitted to connect to the electrical grid in order to feed into the grid electricity generated by the eligible farm from its facilities that generate electricity from a waste-to-energy technology.

C. The Commission shall adopt regulations to implement this section pursuant to § 56-578.

2009, c. 746.

§ 56-594.2. Small agricultural generators.

A. As used in this section:

"Small agricultural generating facility" means an electrical generating facility that:

1. Has a capacity:

a. Of not more than 1.5 megawatts; and

b. That does not exceed 150 percent of the customer's expected annual energy consumption based on the previous 12 months of billing history or an annualized calculation of billing history if 12 months of billing history is not available;

2. Uses as its total source of fuel renewable energy;

3. Is located on the customer's premises and is interconnected with its utility through a separate meter;

4. Is interconnected and operated in parallel with an electric utility's distribution but not transmission facilities;

5. Is designed so that the electricity generated by the facility is expected to remain on the utility's distribution system; and

6. Is a qualifying small power production facility pursuant to the Public Utility Regulatory Policies Act of 1978 (P.L. 95-617).

"Small agricultural generator" means a customer that:

1. Is not an eligible agricultural customer-generator pursuant to § 56-594;

2. Operates a small agricultural generating facility as part of an agricultural business;

3. May be served by multiple meters that are located at separate but contiguous sites;

4. May aggregate the electricity consumption measured by the meters, solely for purposes of calculating 150 percent of the customer's expected annual energy consumption, but not for billing or retail service purposes, provided that the same utility serves all of its meters;

5. Uses not more than 25 percent of contiguous land owned or controlled by the agricultural business for purposes of the renewable energy generating facility; and

6. Issues a certification under oath as to the amount of land being used for renewable generation.

"Utility" includes supplier or distributor, as applicable.

B. A small agricultural generator electing to interconnect pursuant to this section shall:

1. Enter into a power purchase agreement with its utility to sell all of the electricity generated from its small agricultural generating facility, which power purchase agreement obligates the utility to purchase all the electricity generated, at a rate agreed upon by the parties, but at a rate not less than the utility's Commission-approved avoided cost tariff for energy and capacity;

2. Have the rights described in subsection E of § 56-594 pertaining to an eligible agricultural customer-generator as to the renewable energy certificates or other environmental attributes generated by the renewable energy generating facility;

3. Abide by the appropriate small generator interconnection process as described in 20VAC5-314; and

4. Pay to its utility any necessary additional expenses as required by this section.

C. Utilities:

1. Shall purchase, through the power purchase agreement described in subdivision B 1, all of the output of the small agricultural generator;

2. Shall recover the cost for its distribution facilities to the generating meter either through a proportional cost-sharing agreement with the small agricultural generator or through metering the total capacity and energy placed on the distribution system by the small agricultural generator;

3. Shall recover all costs incurred by the utility to purchase electricity, capacity, and renewable energy certificates from the small agricultural generator:

a. If the utility has a Commission-approved Renewable Energy Portfolio Standard (RPS) plan and rate adjustment clause, through the utility's RPS rate adjustment clause; or

b. If the utility does not have a Commission-approved RPS rate adjustment clause, through the utility's fuel adjustment clause or through the utility's cost of purchased power;

4. May conduct settlement transactions for purchased power in dollars on the small agricultural generator's electric bill or through other means of settlement, in the utility's sole discretion;

5. Shall bill the small agricultural generator eligible costs for small generator interconnection studies required pursuant to the appropriate small generator interconnection process described in subdivision B 3; and

6. Shall bill its expenses, at cost, for any additional engineering studies that a small agricultural generator is required to pay prior to interconnection.

2017, cc. 565, 581.

§ 56-595. Repealed.

Repealed by Acts 2003, c. 885.

§ 56-596. Consideration of economic development; report.

A. In all relevant proceedings pursuant to this Act, the Commission shall take into consideration, among other things, the goal of economic development in the Commonwealth.

B. By September 1 of each year, the Commission shall report to the Commission on Electric Utility Regulation and the Governor on the status of the implementation of this chapter and its recommendations regarding the implementation of the provisions of this chapter. This report shall include the Commission's recommendations for any actions by the General Assembly, the Commission, electric utilities, or any other entity that the Commission considers to be in the public interest.

2001, c. 748; 2003, c. 885; 2008, c. 883.

The chapters of the acts of assembly referenced in the historical citation at the end of these sections may not constitute a comprehensive list of such chapters and may exclude chapters whose provisions have expired.

The Virginia General Assembly is offering access to the Code of Virginia on the Internet as a service to the public. We are unable to assist users of this service with legal questions nor respond to requests for legal advice or the application of the law to specific facts. Therefore, to understand and protect your legal rights, you should consult an attorney.

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