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2010 SESSION

10105450D
SENATE BILL NO. 680
FLOOR AMENDMENT IN THE NATURE OF A SUBSTITUTE
(Proposed by Delegate Armstrong
on February 17, 2010)
(Patron Prior to Substitute--Senator Puckett)
A BILL to amend and reenact §§ 56-234.2, 56-235.2, 56-235.6, 56-238, 56-249.6, 56-577, 56-580, 56-581, 56-585.1, 56-585.2, and 56-598 of the Code of Virginia and to amend the Code of Virginia by adding a section numbered 56-585.1:1, relating to investor-owned electric utility rates.

Be it enacted by the General Assembly of Virginia:

1. That §§ 56-234.2, 56-235.2, 56-235.6, 56-238, 56-249.6, 56-577, 56-580, 56-581, 56-585.1, 56-585.2, and 56-598 of the Code of Virginia are amended and reenacted and that the Code of Virginia is amended by adding a section numbered 56-585.1:1 as follows:

§ 56-234.2. Review of rates.

The Commission shall review the rates of any public utility on an annual basis when, in the opinion of the Commission, such annual review is in the public interest, provided that the rates of a public utility (i) subject to § 56-585.1 shall be reviewed in accordance with subsection A of that section or (ii) subject to § 56-585.1:1 shall be reviewed in accordance with that section.

§ 56-235.2. All rates, tolls, etc., to be just and reasonable to jurisdictional customers; findings and conclusions to be set forth; alternative forms of regulation for electric companies.

A. Any rate, toll, charge or schedule of any public utility operating in this Commonwealth shall be considered to be just and reasonable only if: (1) the public utility has demonstrated that such rates, tolls, charges or schedules in the aggregate provide revenues not in excess of the aggregate actual costs incurred by the public utility in serving customers within the jurisdiction of the Commission, including such normalization for nonrecurring costs and annualized adjustments for future costs as the Commission finds reasonably can be predicted to occur during the rate year, and a fair return on the public utility's rate base used to serve those jurisdictional customers, which return shall be calculated in accordance with § 56-585.1 for utilities subject to such section or § 56-585.1:1 for utilities subject to such section; (1a) the investor-owned public electric utility has demonstrated that no part of such rates, tolls, charges or schedules includes costs for advertisement, except for advertisements either required by law or rule or regulation, or for advertisements which solely promote the public interest, conservation or more efficient use of energy; and (2) the public utility has demonstrated that such rates, tolls, charges or schedules contain reasonable classifications of customers. Notwithstanding § 56-234, the Commission may approve, either in the context of or apart from a rate proceeding after notice to all affected parties and hearing, special rates, contracts or incentives to individual customers or classes of customers where it finds such measures are in the public interest. Such special charges shall not be limited by the provisions of § 56-235.4. In determining costs of service, the Commission may use the test year method of estimating revenue needs. In any Commission order establishing a fair and reasonable rate of return for an investor-owned gas, telephone or electric public utility, the Commission shall set forth the findings of fact and conclusions of law upon which such order is based.

For ratemaking purposes, the Commission shall determine the federal and state income tax costs for investor-owned water, gas, or electric 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. The Commission shall, before approving special rates, contracts, incentives or other alternative regulatory plans under subsection A, ensure that such action (i) protects the public interest, (ii) will not unreasonably prejudice or disadvantage any customer or class of customers, and (iii) will not jeopardize the continuation of reliable electric service.

C. After notice and public hearing, the Commission shall issue guidelines for special rates adopted pursuant to subsection A that will ensure that other customers are not caused to bear increased rates as a result of such special rates.

§ 56-235.6. Optional performance-based regulation of certain utilities.

A. Notwithstanding any provision of law to the contrary, the Commission may approve a performance-based ratemaking methodology for any public utility engaged in the business of furnishing gas service (for the purposes of this section a "gas utility") or electricity service (for the purposes of this section an "electric utility"), upon application of the gas utility or electric utility, and after such notice and opportunity for hearing as the Commission may prescribe. For the purposes of this section, "performance-based ratemaking methodology" shall mean a method of establishing rates and charges that are in the public interest, and that departs in whole or in part from the cost-of-service methodology set forth in § 56-235.2.

B. The Commission shall approve such performance-based ratemaking methodology if it finds that it: (i) preserves adequate service to all classes of customers ( including transportation-only customers if for a gas utility); (ii) does not unreasonably prejudice or disadvantage any class of gas utility or electric utility customers; (iii) provides incentives for improved performance by the gas utility or electric utility in the conduct of its public duties; (iv) results in rates that are not excessive; and (v) is in the public interest. Performance-based forms of regulation may include, but not be limited to, fixed or capped base rates, the use of revenue indexing, price indexing, ranges of authorized return, gas cost indexing for gas utilities, and innovative utilization of utility-related assets and activities (such as a gas utility's off-system sales of excess gas supplies and release of upstream pipeline capacity, performance of billing services for other gas or electricity suppliers, and reduction or elimination of regulatory requirements) in ways that benefit both the utility and its customers and may include a mechanism for automatic annual adjustments to revenues or prices to reflect changes in any index adopted for the implementation of such performance-based form of regulation. In making the findings required by this subsection, the Commission shall include, but not be limited to, in its considerations: (i) any proposed measures, including investments in infrastructure, that are reasonably estimated to preserve or improve system reliability, safety, supply diversity, and gas utility transportation options; and (ii) other customer benefits that are reasonably estimated to accrue from the gas or electric utility's proposal.

C. Each gas utility or electric utility shall have the option to apply for implementation of a performance-based form of regulation. If the Commission approves the application with modifications, the gas utility or electric utility may, at its option, withdraw its application and continue to be regulated under the form of regulation that existed immediately prior to the filing of the application. The Commission may, after notice and opportunity for hearing, alter, amend or revoke, or authorize a gas utility or electric utility to discontinue, a performance-based form of regulation previously implemented under this section if it finds that (i) service to one or more classes of customers has deteriorated, or will deteriorate, to the point that the public interest will not be served by continuation of the performance-based form of regulation; (ii) any class of gas utility customer or electric utility customer is being unreasonably prejudiced or disadvantaged by the performance-based form of regulation; (iii) the performance-based form of regulation does not, or will not, provide reasonable incentives for improved performance by a gas utility or electric utility in the conduct of its public duties (which determination may include, but not be limited to, consideration of whether rates are inadequate to recover a gas utility's or electric utility's cost of service); (iv) the performance-based form of regulation is resulting in rates that are excessive compared to a gas utility's or electric utility's cost of service and any benefits that accrue from the performance-based plan; (v) the terms ordered by the Commission in connection with approval of a gas utility's or electric utility's implementation of a performance-based form of regulation have been violated; or (vi) the performance-based form of regulation is no longer in the public interest. Any request by a gas utility or electric utility to discontinue its implementation of a performance-based form of regulation may include application pursuant to this chapter for approval of new rates under the standards of § 56-235.2 for a gas utility or pursuant to § 56-585.1 or 56-585.1:1 for an investor-owned incumbent electric utility.

D. The Commission shall use the annual review process established in § 56-234.2 to monitor each performance-based form of regulation approved under this section and to make any annual prospective adjustments to revenues or prices necessary to reflect increases or decreases in any index adopted for the implementation of such performance-based form of regulation.

§ 56-238. Suspension of proposed rates, etc.; investigation; effectiveness of rates pending investigation and subject to bond; fixing reasonable rates, etc.

The Commission, either upon complaint or on its own motion, may suspend the enforcement of any or all of the proposed rates, tolls, charges, rules or regulations, of any public utility except an investor-owned electric public utility for a period not exceeding 150 days from the date of filing, and the Commission shall suspend the enforcement of all of the proposed rates, tolls, charges, rules or regulations of an investor-owned electric public utility until the Commission's final order in the proceeding, during which time it times the Commission shall investigate the reasonableness or justice of the proposed rates, tolls, charges, rules and regulations and thereupon fix and order substituted therefor such rates, tolls, charges, rules and regulations as shall be just and reasonable. The Commission's final order in such a proceeding involving an investor-owned electric public utility that is filed after January 1, 2010, shall be entered not more than nine months after the date of filing, at which time the suspension period shall expire, and any revisions in rates or credits so ordered shall take effect not more than 60 days after the date of the order. Notice of the suspension of any proposed rate, toll, charge, rule or regulation shall be given by the Commission to the public utility, prior to the expiration of the thirty 30 days' notice to the Commission and the public heretofore provided for. If the proceeding has not been concluded and an order made at the expiration of the suspension period, after notice to the Commission by the public utility making the filing, the proposed rates, tolls, charges, rules or regulations shall go into effect. Where increased rates, tolls or charges are thus made effective, the Commission shall, by order, require the public utility to furnish a bond, to be approved by the Commission, to refund any amounts ordered by the Commission, to keep accurate accounts in detail of all amounts received by reason of such increase, and upon completion of the hearing and decision, to order such public utility to refund, with interest at a rate set by the Commission, the portion of such increased rates, tolls or charges by its decision found not justified. The Commission shall prescribe all necessary rules and regulations to effectuate the purposes of this section on or before September 1, 1980. This section shall not apply to proceedings conducted pursuant to § 56-245 or 56-249.6.

§ 56-249.6. Recovery of fuel and purchased power costs.

A. 1. Each electric utility that purchases fuel for the generation of electricity or purchases power and that was not, as of July 1, 1999, bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, shall submit to the Commission its estimate of fuel costs, including the cost of purchased power, for the 12-month period beginning on the date prescribed by the Commission. Upon investigation of such estimates and hearings in accordance with law, the Commission shall direct each company to place in effect tariff provisions designed to recover the fuel costs determined by the Commission to be appropriate for that period, adjusted for any over-recovery or under-recovery of fuel costs previously incurred.

2. The Commission shall continuously review fuel costs and if it finds that any utility described in subdivision A 1 is in an over-recovery position by more than five percent, or likely to be so, it may reduce the fuel cost tariffs to correct the over-recovery.

3. Beginning July 1, 2009, for all utilities described in subdivision A 1 and subsection B, if the Commission approves any increase in fuel factor charges pursuant to this section that would increase the total rates of the residential class of customers of any such utility by more than 20 percent, the Commission, within six months following the effective date of such increase, shall review fuel costs, and if the Commission finds that the utility is, or is likely to be, in an over-recovery position with respect to fuel costs for the 12-month period for which the increase in fuel factor charges was approved by more than five percent, it may reduce the utility's fuel cost tariffs to correct the over-recovery.

B. All fuel costs recovery tariff provisions in effect on January 1, 2004, for any electric utility that purchases fuel for the generation of electricity and 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, shall remain in effect until the later of (i) July 1, 2007 or (ii) the establishment of tariff provisions under subsection C. Any such utility shall continue to report to the Commission annually its actual fuel costs, including the cost of purchased power.

C. Each electric utility described in subsection B shall submit annually to the Commission its estimate of fuel costs, including the cost of purchased power, for successive 12-month periods beginning on July 1, 2007, and each July 1 thereafter. Upon investigation of such estimates and hearings in accordance with law, the Commission shall direct each such utility to place in effect tariff provisions designed to recover the fuel costs determined by the Commission to be appropriate for such periods, adjusted for any over-recovery or under-recovery of fuel costs previously incurred; however, (i) no such adjustment for any over-recovery or under-recovery of fuel costs previously incurred shall be made for any period prior to July 1, 2007, and (ii) the Commission shall order that the deferral portion, if any, of the total increase in fuel tariffs for all classes as determined by the Commission to be appropriate for the 12-month period beginning July 1, 2007, above the fuel tariffs previously existing, shall be deferred without interest and recovered from all classes of customers as follows: (i) in the 12-month period beginning July 1, 2008, that part of the deferral portion of the increase in fuel tariffs that the Commission determines would increase the total rates of the residential class of customers of the utility by four percent over the level of such total rates in existence on June 30, 2008, shall be recovered; (ii) in the 12-month period beginning July 1, 2009, that part of the balance of the deferral portion of the increase in fuel tariffs, if any, that the Commission determines would increase the total rates of the residential class of customers of the utility by four percent over the level of such total rates in existence on June 30, 2009, shall be recovered; and (iii) in the 12-month period beginning July 1, 2010, the entire balance of the deferral portion of the increase in fuel tariffs, if any, shall be recovered. The "deferral portion of the increase in fuel tariffs" means the portion of such increase in fuel tariffs that exceeds the amount of such increase in fuel tariffs that the Commission determines would increase the total rates of the residential class of customers of the utility by more than four percent over the level of such total rates in existence on June 30, 2007.

D. In proceedings under subsections A and C:

1. Energy revenues associated with off-system sales of power shall be credited against fuel factor expenses in an amount equal to the total incremental fuel factor costs incurred in the production and delivery of such sales. In addition, 75 percent of the total annual margins from off-system sales shall be credited against fuel factor expenses; however, the Commission, upon application and after notice and opportunity for hearing, may require that a smaller percentage of such margins be so credited if it finds by clear and convincing evidence that such requirement is in the public interest. The remaining margins from off-system sales shall not be considered in the biennial reviews of electric utilities conducted pursuant to § 56-585.1 or 56-585.1:1. In the event such margins result in a net loss to the electric utility, (i) no charges shall be applied to fuel factor expenses and (ii) any such net losses shall not be considered in the biennial reviews of electric utilities conducted pursuant to § 56-585.1 if the utility, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, or § 56-585.1:1 if the utility, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002. For purposes of this subsection, "margins from off-system sales" shall mean the total revenues received from off-system sales transactions less the total incremental costs incurred; and

2. The Commission shall disallow recovery of any fuel costs that it finds without just cause to be the result of failure of the utility to make every reasonable effort to minimize fuel costs or any decision of the utility resulting in unreasonable fuel costs, giving due regard to reliability of service and the need to maintain reliable sources of supply, economical generation mix, generating experience of comparable facilities, and minimization of the total cost of providing service.

E. The Commission is authorized to promulgate, in accordance with the provisions of this section, all rules and regulations necessary to allow the recovery by electric utilities of all of their prudently incurred fuel costs under subsections A and C, including the cost of purchased power, as precisely and promptly as possible, with no over-recovery or under-recovery, except as provided in subsection C, in a manner that will tend to assure public confidence and minimize abrupt changes in charges to consumers.

§ 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 if the utility, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, or § 56-585.1:1 if the utility, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002. 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 the utility, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, or § 56-585.1:1 if the utility, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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 if the utility, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, or pursuant to the provisions of subdivision A 2 of § 56-585.1:1 if the utility, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002. 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 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, except for any incumbent electric utility other than 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.

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.

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

A. Subject to the provisions of §§ 56-585.1 and 56-585.1:1, 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 or 56-585.1:1, 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 and 56-585.1:1, 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.

§ 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 and 56-585.1:1, 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 and 56-585.1:1.

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.

§ 56-585.1. Generation, distribution, and transmission rates for certain electric utilities.

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.) of this title, 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) 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 that (i) as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, as provided in § 56-585.1:1, and (ii) as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, in accordance with 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 conduct its biennial reviews of such 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 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, such action being referred to in this section as a Performance Incentive. If the Commission adopts such Performance Incentive, it shall remain in effect without change until the next biennial review for such utility is concluded and shall not be modified pursuant to any provision of the remainder of this subsection.

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 Performance Incentive adopted by the Commission, or 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, including the determination of whether to adopt a Performance Incentive and the amount thereof, 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 both the generation and distribution services is no more than 50 basis points above or below the return as so determined, such combined return shall not be considered either excessive or insufficient, respectively.

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 2012, consisting of the schedules contained in the Commission's rules governing utility rate increase applications (20 VAC 5-200-30); however, if the Commission elects to stagger the dates of the biennial reviews of utilities as provided in subdivision 1, then Phase I utilities shall commence biennial filings in 2011 and Phase II utilities 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 4 or 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.

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 A 2 of this section. 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; and

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. If the Commission determines it would be just, reasonable, and in the public interest, the Commission may include the enhanced rate of return on common equity prescribed in subdivision 6 in a rate adjustment clause approved hereunder for a project whose purpose is to reduce the need for construction of new generation facilities by enabling the continued operation of existing generation facilities. In the event the Commission includes such enhanced return in such rate adjustment clause, the project that is the subject of such clause shall be treated as a facility described in subdivision 6 for the purposes of this section.

The Commission shall have the authority to determine the duration or amortization period for any adjustment clause approved under this subdivision.

6. To ensure 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, or (iii) one or more major unit modifications of generation facilities; however, 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 any such facility 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 costs, life-cycle costs, 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. 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 the facility begins commercial operation. 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 the facility begins commercial operation, 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. No change shall be made to any Performance Incentive previously adopted by the Commission in implementing any rate of return under this subdivision. 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) is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title. The basis points to be added to the utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table: 


  Type of Generation Facility    Basis Points      First Portion of 
                                                   Service Life
  Nuclear-powered                200               Between 12 and 25 
                                                   years
  Carbon capture compatible,
  clean-coal powered             200               Between 10 and 20 
                                                   years
  Renewable powered              200               Between 5 and 15 
                                                   years
  Conventional coal or combined-
  cycle combustion turbine       100               Between 10 and 20 
                                                   years 

Generation facilities described in clause (ii) that utilize simple-cycle combustion turbines shall not 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.

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 clause (a) of subdivision 5, or that are related to facilities and projects described in clause (i) 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. 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) 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 subdivisions 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). 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. If the Commission determines as a result of such biennial review that:

(i) 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 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, 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 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 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;

(ii) 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 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, 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 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

(iii) 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 both 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 clause (ii) of this subdivision, 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 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 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 nine months after the end of the test period, and any revisions in rates or credits so ordered shall take effect not more than 60 days after the date of the order.

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 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, 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 clauses (ii) and (iii) of subdivision 8 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 above such fair combined rate of return shall be credited to customers' bills, in lieu of the provisions of clauses (ii) and (iii) of subdivision 8. Any such credits shall be amortized and allocated among customer classes in the manner provided by clause (ii) of subdivision 8. 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 clause (i) of subdivision 8; (iv) revisions to the utility's rates pursuant to the Commission's rules governing utility rate increase applications (20 VAC 5-200-30), 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 clauses (i) and (iii) of subdivision 8, 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 that, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, from applying for an increase in rates pursuant to § 56-245 or the Commission's rules governing utility rate increase applications (20 VAC 5-200-30); however, in any such filing, a fair rate of return on common equity shall be determined pursuant to subdivision 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 that, as of July 1, 1999, were bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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.) of this title, including specifically § 56-235.2.

D. Nothing in this section shall preclude the Commission from determining, 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 that, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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.) of this title.

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

§ 56-585.1:1. Alternative method for setting rates of certain electric utilities.

A. 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 that, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, in accordance with 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 conduct its biennial reviews of such utilities by utilizing the two successive 12-month test periods ending December 31, 2010, with subsequent proceedings utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted.

2. The 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 in the manner provided in subdivision A 2 of § 56-585.1 with respect to investor-owned incumbent electric utilities that, as of July 1, 1999, were bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002.

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. 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.

4. A utility subject to this section shall be authorized to seek recovery, as part of the biennial review of its rates, terms and conditions for the provision of generation, distribution, and transmission services, of the following costs, the 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. Retail rates to recover reasonable and prudent costs shall be designed using the appropriate billing determinants in the retail rate schedules.

5. A utility subject to this section shall be authorized to seek recovery, as part of the biennial review of its rates, terms and conditions for the provision of generation, distribution, and transmission services, 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 allow the recovery of such costs that comply with the requirements of clause (vi) of subsection B of § 56-582;

b. Reasonable costs of designing and operating fair and effective peak-shaving programs that the Commission finds are in the public interest;

c. Reasonable costs of designing, implementing, and operating energy efficiency programs that the Commission finds are 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:

(1) Assigned to any customer that has a verifiable history of having used more than 10 megawatts of demand from a single meter of delivery; or

(2) 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 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 subdivision, the Commission shall take into consideration the goals of economic development, energy efficiency and environmental protection in the Commonwealth;

d. Reasonable costs of participation in a renewable energy portfolio standard program, including administrative costs, ancillary costs, capacity costs, costs of energy represented by certificates described in subsection A of § 56-585.2, if the Commission has approved the utility's participation in such program pursuant to § 56-585.2, provided the costs are not recoverable under subdivision 6; and

e. 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 permit the recovery of such costs if it finds that such costs are necessary to comply with such environmental laws or regulations. If the Commission determines it would be just, reasonable, and in the public interest, the Commission may permit the utility to earn the enhanced rate of return on common equity prescribed in subdivision 6 for such costs of a project the purpose of which is to reduce the need for construction of new generation facilities by enabling the continued operation of existing generation facilities. If the Commission permits the utility to earn an enhanced return on such costs, the project for which the costs are incurred shall be treated as a facility described in subdivision 6 for the purposes of this section.

6. To ensure a reliable and adequate supply of electricity, to meet the utility's projected native load obligations, and to promote economic development, a utility shall be authorized to seek recovery, as part of the biennial review of its rates, terms and conditions for the provision of generation, distribution, and transmission services, of the costs of one or more generation facilities or one or more major unit modifications of generation facilities. A utility that constructs any such facility 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 costs, life-cycle costs, 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. 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 the facility begins commercial operation. 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 the facility begins commercial operation, 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 costs of the facility. No change shall be made to any Performance Incentive previously adopted by the Commission in implementing any rate of return under this subdivision. 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 basis points to be added to the utility's general rate of return to calculate the enhanced rate of return on common equity, and the first portion of that facility's service life to which such enhanced rate of return shall be applied, shall vary by type of facility, as specified in the following table: 


  Type of Generation Facility    Basis Points   First Portion of 
                                                Service Life
  Nuclear-powered                 200      Between 12 and 25 
                                                  years
  Carbon capture compatible,
  clean-coal powered              200      Between 10 and 20 
                                                     years
  Renewable powered               200      Between 5 and 15 
                                                 years
  Conventional coal or combined-
  cycle combustion turbine        100      Between 10 and 20 
                                                years 

Generation facilities that utilize simple-cycle combustion turbines shall not 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.

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.

7. The ability of a utility to recover, in a biennial review, the costs described in subdivision 4, 5, or 6, shall be considered with due regard to the other costs, revenues, investments, or earnings of the utility.

8. If the Commission determines as a result of a 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 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, 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 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 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 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, 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 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 both 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 8 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 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 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 nine months after the end of the test period, and any revisions in rates or credits so ordered shall take effect not more than 60 days after the date of the order.

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, 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 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, 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 8 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 above such fair combined rate of return shall be credited to customers' bills, in lieu of the provisions of subdivisions 8 b and 8 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 (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) revisions to the utility's rates pursuant to subdivision 8 a; (iii) 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 (iv) 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 8 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 that, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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 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 that, as of July 1, 1999, were not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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. Nothing in this section shall preclude the Commission from determining, 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 that, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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.).

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

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

A. As used in this section:

"Renewable energy" shall have the same meaning ascribed to it in § 56-576, provided such renewable energy is (i) generated or purchased 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; (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 a control area adjacent to such interconnection region; or (iii) represented by certificates issued by an affiliate of such regional transmission entity, or any successor to such affiliate, and held or acquired by such utility, which validate the generation of renewable energy by eligible sources in such region. "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.

"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 to achieve the goals set forth in subsection D, such goals being referred to herein as "RPS Goals". Accordingly, the Commission, in addition to providing recovery of incremental RPS program costs pursuant to subsection E, shall increase the fair combined rate of return on common equity for each utility participating in such program by a single Performance Incentive, as defined in subdivision A 2 of § 56-585.1 or subdivision A 2 of § 56-585.1:1, as applicable, of 50 basis points whenever the utility attains an RPS Goal established in subsection D. Such Performance Incentive shall first be used in the calculation of a fair combined rate of return for the purposes of the immediately succeeding biennial review conducted pursuant to § 56-585.1 or 56-585.1:1 after any such RPS Goal is attained, and shall remain in effect if the utility continues to meet the RPS Goals established in this section through and including the third succeeding biennial review conducted thereafter. Any such Performance Incentive, if implemented, shall be in lieu of any other Performance Incentive reducing or increasing such utility's fair combined rate of return on common equity for the same time periods. However, if the utility receives any other Performance Incentive increasing its fair combined rate of return on common equity by more than 50 basis points, the utility shall be entitled to such other Performance Incentive in lieu of this Performance Incentive during the term of such other Performance Incentive. A utility shall receive double credit toward meeting the renewable energy portfolio standard for energy derived from sunlight or from wind.

D. To qualify for the Performance Incentive established in subsection C, the total electric energy sold by a utility to meet the RPS Goals shall be composed of the following amounts of electric energy 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 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 Goal.

E. A utility participating in such program that, as of July 1, 1999, was bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, 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. A utility participating in such program that, as of July 1, 1999, was not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, shall have the right to recover its reasonable incremental costs incurred for the purpose of participating in such program in the utility's biennial rate review as provided in subdivision A 5 d of § 56-585.1:1. All incremental costs of the RPS program of either type of participating utility 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. 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. 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 on (i) its efforts, if any, to meet the RPS Goals, (ii) its overall generation of renewable energy, and (iii) advances in renewable generation technology that affect activities described in clauses (i) and (ii).

§ 56-598. Contents of integrated resource plans.

An IRP should:

1. Integrate, over the planning period, the electric utility's forecast of demand for electric generation supply with recommended plans to meet that forecasted demand and assure adequate and sufficient reliability of service, including, but not limited to:

a. Generating electricity from generation facilities that it currently operates or intends to construct or purchase;

b. Purchasing electricity from affiliates and third parties; and

c. Reducing load growth and peak demand growth through cost-effective demand reduction programs;

2. Identify a portfolio of electric generation supply resources, including purchased and self-generated electric power, that:

a. Consistent with § 56-585.1 or 56-585.1:1, is most likely to provide the electric generation supply needed to meet the forecasted demand, net of any reductions from demand side programs, so that the utility will continue to provide reliable service at reasonable prices over the long term; and

b. Will consider low cost energy/capacity available from short-term or spot market transactions, consistent with a reasonable assessment of risk with respect to both price and generation supply availability over the term of the plan;

3. Reflect a diversity of electric generation supply and cost-effective demand reduction contracts and services so as to reduce the risks associated with an over-reliance on any particular fuel or type of generation demand and supply resources and be consistent with the Commonwealth's energy policies as set forth in § 67-102; and

4. Include such additional information as the Commission requests pertaining to how the electric utility intends to meets its obligation to provide electric generation service for use by its retail customers over the planning period.

2. That an incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the State Corporation Commission that extended in its application beyond January 1, 2002, shall suspend the collection of interim rates during the pendency of the Commission's consideration of the utility's application brought pursuant to subsection A of § 56-585.1 of the Code of Virginia and filed on July 15, 2009. To determine if a refund is required for the period when interim rates were in effect before such suspension, the Commission shall offset any required refund, which is the amount of revenue collected while the interim rates were in effect that exceeds the amount approved by the Commission in its final order on the utility's application, by the amount of revenue that the utility would have collected had the rates ultimately approved by the Commission in its final order on the utility's application been in effect during the period between the date such suspension commenced and the effective date of the rates approved by the Commission in its final order. The Commission shall issue its final order on the utility's application not later than July 15, 2010, for rates to become effective for bills rendered on and after August 1, 2010, notwithstanding the provisions of subsection A of § 56-235.4 of the Code of Virginia.

3. That an emergency exists and this act is in force from its passage.