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2007 SESSION


CHAPTER 888
An Act to amend and reenact §§ 56-233.1, 56-234.2, 56-235.2, 56-235.6, 56-249.6, 56-576 through 56-581, 56-582, 56-584, 56-585, 56-587, 56-589, 56-590, and 56-594 of the Code of Virginia, to amend the Code of Virginia by adding sections numbered 56-585.1, 56-585.2, and 56-585.3, and to repeal §§ 56-581.1 and 56-583 of the Code of Virginia, relating to the regulation of electric utility service.
[H 3068]
Approved April 4, 2007

 

Be it enacted by the General Assembly of Virginia:

1.  That §§ 56-233.1, 56-234.2, 56-235.2, 56-235.6, 56-249.6, 56-576 through 56-581, 56-582, 56-584, 56-585, 56-587, 56-589, 56-590, and 56-594 of the Code of Virginia are amended and reenacted and that the Code of Virginia is amended by adding sections numbered 56-585.1, 56-585.2, and 56-585.3 as follows:

§ 56-233.1. Public utilities purchasing practices.

Every public utility subject to the annual biennial review provisions of Title 56 shall use competitive bidding to the extent practicable in its purchasing and construction practices. In addition, all such public utilities shall file with the Commission and keep current a description of its purchasing and construction practices.

§ 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 subject to § 56-585.1 shall be reviewed in accordance with subsection A of 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, subject to including such normalization for nonrecurring costs and annualized adjustments for known future increases in costs as the Commission may deem reasonable 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; (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, but shall not consider any adjustments or expenses that are speculative or cannot be predicted with reasonable certainty. 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.

B. Upon application of any public service company furnishing electric service or on the Commission's own motion, the Commission may approve after notice to all affected parties and hearing, an alternative form of regulation. Alternatives may include, but are not limited to, the use of price regulation, ranges of authorized returns, categories of services, price indexing or other alternative forms of regulation.

C. The Commission shall, before approving special rates, contracts, incentives or other alternative regulatory plans under subsections subsection A and B, 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.

D 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"), either upon application of the gas utility or upon its own motion 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 gas 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) gas 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 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 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.

§ 56-249.6. 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.

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 earlier later of (i) July 1, 2007; (ii) the termination of capped rates pursuant to the provisions of subsection C of § 56-582; or (iii) (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 until July 1, 2007.

C. Until the capped rates for such utility expire or are terminated pursuant to the provisions of § 56-582, each 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 the successive 12-month periods beginning on July 1, 2007, 2008, and 2009, and the six-month period beginning July 1, 2010 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 may shall order that up to 40% the deferral portion, if any, of any 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 during the period from July 1, 2008, through December 31, 2010 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. 1. In proceedings under subsections A and C, the Commission may, to the extent deemed appropriate, offset against fuel costs and purchased power costs to be recovered the revenues attributable to sales of power pursuant to interconnection agreements with neighboring electric utilities.:

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. 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. 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. In proceedings under subsections A and C, the  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.

3 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.

The Commission may, however, dispense with the procedures set forth above for any electric utility if it finds, after notice and hearing, that the electric utility's fuel costs can be reasonably recovered through the rates and charges investigated and established in accordance with other sections of this chapter.

§ 56-576. Definitions.

As used in this chapter:

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

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

"Billing services" means services related to billing customers for competitive electric services or billing customers on a consolidated basis for both competitive and regulated electric services.

"Commission" means the State Corporation Commission.

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

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

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

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

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

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

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

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

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

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

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

"Market power" means the ability to impose on customers a significant and nontransitory price increase on a product or service in a market above the price level which would prevail in a competitive market.

"Metering services" means the ownership, installation, maintenance, or reading of electric meters and includes meter data management services.

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

"Period of transition to customer choice" means the period beginning on January 1, 2002, and ending on January 1, 2004, unless otherwise extended by the Commission pursuant to this chapter, during which the Commission and all electric utilities authorized to do business in the Commonwealth shall implement customer choice for retail customers in the Commonwealth.

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

"Renewable energy" means energy derived from sunlight, wind, falling water, sustainable biomass, energy from waste, wave motion, tides, and geothermal power, and does not include energy derived from coal, oil, natural gas or nuclear power.

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

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

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

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

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

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

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

A. The transition to retail Retail competition for the purchase and sale of electric energy shall be implemented as follows 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. On and after January 1, 2002, retail customers of electric energy within the Commonwealth shall be permitted to purchase energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth during and after the period of transition to retail competition, subject to the following:

a. The Commission shall separately establish for each utility a phase-in schedule for customers by class, and by percentages of class, to ensure that by January 1, 2004, all retail customers of each utility are permitted to purchase electric energy from any supplier of electric energy licensed to sell retail electric energy within the Commonwealth.

b. The Commission shall also ensure that residential and small business retail customers are permitted to select suppliers in proportions at least equal to that of other customer classes permitted to select suppliers during the period of transition to retail competition.

3. On and after January 1, 2002, the The generation of electric energy shall no longer be subject to regulation under this title, except as specified in this chapter.

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

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

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

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

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

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

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

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

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

5. After the expiration or termination of capped rates, individual retail customers of electric energy within the Commonwealth, regardless of customer class, shall be permitted to purchase electric energy provided 100% 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% from renewable energy.

B. The Commission may delay or accelerate the implementation of any of the provisions of this section, subject to the following:

1. Any such delay or acceleration shall be based on considerations of reliability, safety, communications or market power; and

2. Any such delay shall be limited to the period of time required to resolve the issues necessitating the delay, but in no event shall any such delay extend the implementation of customer choice for all customers beyond January 1, 2005.

The Commission shall, within a reasonable time, report to the General Assembly, or any legislative entity monitoring the restructuring of Virginia's electric industry, any such delays and the reasons therefor.

C. The Commission may conduct pilot programs encompassing retail customer choice of electricity energy suppliers for each incumbent electric utility that has not transferred functional control of its transmission facilities to a regional transmission entity prior to January 1, 2003. Upon application of an incumbent electric utility, the Commission may establish opt-in and opt-out municipal aggregation pilots and any other pilot programs the Commission deems to be in the public interest, and the Commission shall report to the Commission on Electric Utility Restructuring on the status of such pilots by November of each year through 2006.

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

E 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 subdivision subsection C 1 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 subdivision subsection B 3 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.

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

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

B. Except as otherwise provided in this chapter, every distributor shall provide distribution service within its service territory on a basis which is just, reasonable, and not unduly discriminatory to suppliers of electric energy, including distributed generation, as the Commission may determine. The distribution services provided to each supplier of electric energy shall be comparable in quality to those provided by the distribution utility to itself or to any affiliate. The Commission shall establish rates, terms and conditions for distribution service under Chapter 10 (§ 56-232 et seq.) of this title.

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

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

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

F. If the Commission determines that increases in the capacity of the transmission systems in the Commonwealth, or modifications in how such systems are planned, operated, maintained, used, financed or priced, will promote the efficient development of competition in the sale of electric energy, the Commission may, to the extent not preempted by federal law, require one or more persons having any ownership or control of, or responsibility to operate, all or part of such transmission systems to:

1. Expand the capacity of transmission systems;

2. File applications and tariffs with the Federal Energy Regulatory Commission (FERC) which (i) make transmission systems capacity available to retail sellers or buyers of electric energy under terms and conditions described by the Commission and (ii) require owners of generation capacity located in the Commonwealth to bear an appropriate share of the cost of transmission facilities, to the extent such cost is attributable to such generation capacity;

3. Enter into a contract with, or provide information to, a regional transmission entity; or

4. Take such other actions as the Commission determines to be necessary to carry out the purposes of this chapter.

G. If the Commission determines, after notice and opportunity for hearing, that a person has or will have, as a result of such person's control of electric generating capacity or energy within a transmission constrained area, market power over the sale of electric generating capacity or energy to retail customers located within the Commonwealth, the Commission may, to the extent not preempted by federal law and to the extent that the Commission determines market power is not adequately mitigated by rules and practices of the applicable regional transmission entity having responsibility for management and control of transmission assets within the Commonwealth, adjust such person's rates for such electric generating capacity or energy, only within such transmission-constrained area and only to the extent necessary to protect retail customers from such market power. Such rates shall remain regulated until the Commission, after notice and opportunity for hearing, determines that the market power has been mitigated.

§ 56-579. Regional transmission entities.

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

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

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

a. Promote:

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

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

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

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

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

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

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

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

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

2. The laws of this Commonwealth concerning the exercise of the right of eminent domain by a public service corporation pursuant to the provisions of Article 5 (§ 56-257 et seq.) of Chapter 10 of this title; however, on and after January 1, 2002, a petition may not be filed to exercise the right of eminent domain in conjunction with the construction or enlargement of any utility facility whose purpose is the generation of electric energy; or

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

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

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

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

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

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

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

C. The Commission shall develop codes of conduct governing the conduct of incumbent electric utilities and affiliates thereof when any such affiliates provide, or control any entity that provides, generation, distribution, or transmission or any services made competitive pursuant to § 56-581.1, to the extent necessary to prevent impairment of competition. Nothing in this chapter shall prevent an incumbent electric utility from offering metering options to its customers.

D. The Commission shall permit the construction and operation of electrical generating facilities in Virginia upon a finding that such generating facility and associated facilities (i) will have no material adverse effect upon reliability of electric service provided by any regulated public utility, (ii) are required by the public convenience and necessity, if a petition for such permit is filed after July 1, 2007, and if they are to be constructed and operated by any regulated utility whose rates are regulated pursuant to § 56-585.1, and (ii) (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. 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.

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. Nothing in this chapter shall impair the Commission's Subject to the provisions of § 56-585.1, the Commission shall continue to exercise its existing authority over the provision of electric distribution services to retail customers in the Commonwealth including, but not limited to, the authority contained in Chapters 10 (§ 56-232 et seq.) and 10.1 (§ 56-265.1 et seq.) of this title.

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

G. The applicability of this chapter 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. Subject to the provisions of § 56-582 After the expiration or termination of capped rates except as provided in § 56-585.1, the Commission shall regulate the rates of investor-owned incumbent electric utilities for the transmission of electric energy, to the extent not prohibited by federal law, and for the generation of electric energy and the distribution of electric energy to such retail customers on an unbundled basis, but, subject to the provisions of this chapter after the date of customer choice, the Commission no longer shall regulate rates and services for the generation component of retail electric energy sold to retail customers pursuant to § 56-585.1.

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

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

§ 56-582. Rate caps.

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

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

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

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

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

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

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

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

F. The capped rates established pursuant to this section shall expire on December 31, 2010 2008, unless sooner terminated by the Commission pursuant to the provisions of subsection C; however, rates after the expiration or termination of capped rates shall equal capped rates until such rates are changed pursuant to other provisions of this title.

§ 56-584. Stranded costs.

Just and reasonable net stranded costs, to the extent that they exceed zero value in total for the incumbent electric utility, shall be recoverable by each incumbent electric utility provided each incumbent electric utility shall only recover its just and reasonable net stranded costs through either capped rates as provided in § 56-582 or wires charges as provided in § 56-583. To the extent not preempted by federal law, the establishment by the Commission of wires charges for any distribution cooperative shall be conditioned upon such cooperative entering into binding commitments by which it will pay to any power supply cooperative of which such distribution cooperative is or was a member, as compensation for such power supply cooperative's stranded costs, all or part of the proceeds of such wires charges, as determined by the Commission.

§ 56-585. Default service.

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

B. From time to time, the Commission shall designate one or more providers of default service. In doing so, the Commission:

1. Shall take into account the characteristics and qualifications of prospective providers, including proposed rates, experience, safety, reliability, corporate structure, access to electric energy resources necessary to serve customers requiring such services, and other factors deemed necessary to ensure the reliable provision of such services, to prevent the inefficient use of such services, and to protect the public interest;

2. May periodically, as necessary, conduct competitive bidding processes under procedures established by the Commission and, upon a finding that the public interest will be served, designate one or more willing and suitable providers to provide one or more components of such services, in one or more regions of the Commonwealth, to one or more classes of customers;

3. To the extent that default service is not provided pursuant to a designation under subdivision 2, may require a distributor to provide A distributor shall have the obligation and right to be the supplier of default services in its certificated service territory, and shall do so, in a safe and reliable manner, one or more components of such services, or to form an affiliate to do so, in one or more regions of the Commonwealth, at rates determined pursuant to subsection C and for periods specified by the Commission; however, the Commission may not require a distributor, or affiliate thereof, to provide any such services outside the territory in which such distributor provides service; and

4. Notwithstanding imposition on a distributor by the Commission of the requirement provided in subdivision 3, the Commission may thereafter, upon a finding that the public interest will be served, designate through the competitive bidding process established in subdivision 2 one or more willing and suitable providers to provide one or more components of such services, in one or more regions of the Commonwealth, to one or more classes of customers.

C. If a distributor is required to provide default services pursuant to subdivision B 3, after notice and opportunity for hearing, the Commission shall periodically, for each distributor, determine the rates, terms and conditions for default services, taking into account the characteristics and qualifications set forth in subdivision B 1, as follows:

1. Until the expiration or termination of capped rates, the rates for default service provided by a distributor shall equal the capped rates established pursuant to subdivision A 2 of § 56-582. After the expiration or termination of such capped rates, the rates for default services shall be based upon competitive market prices for electric generation services.

2. The Commission shall, after notice and opportunity for hearing, determine the rates, terms and conditions for default service by such distributor on the basis of the provisions of Chapter 10 (§ 56-232 et seq.) of this title, except that the generation-related components of such rates shall be (i) based upon a plan approved by the Commission as set forth in subdivision 3 or (ii) in the absence of an approved plan, based upon prices for generation capacity and energy in competitive regional electricity markets, except as provided in subsection G.

3. Prior to a distributor's provision of default service, and upon request of such distributor, the Commission shall review any plan filed by the distributor to procure electric generation services for default service. The Commission shall approve such plan if the Commission determines that the procurement of electric generation capacity and energy under such plan is adequately based upon prices of capacity and energy in competitive regional electricity markets. If the Commission determines that the plan does not adequately meet such criteria, then the Commission shall modify the plan, with the concurrence of the distributor, or reject the plan.

4. a. For purposes of this subsection, in determining whether regional electricity markets are competitive and rates for default service, the Commission shall consider (i) the liquidity and price transparency of such markets, (ii) whether competition is an effective regulator of prices in such markets, (iii) the wholesale or retail nature of such markets, as appropriate, (iv) the reasonable accessibility of such markets to the regional transmission entity to which the distributor belongs, and (v) such other factors it finds relevant. As used in this subsection, the term "competitive regional electricity market" means a market in which competition, and not statutory or regulatory price constraints, effectively regulates the price of electricity.

b. If, in establishing a distributor's default service generation rates, the Commission is unable to identify regional electricity markets where competition is an effective regulator of rates, then the Commission shall establish such distributor's default service generation rates by setting rates that would approximate those likely to be produced in a competitive regional electricity market. Such proxy generation rates shall take into account: (i) the factors set forth in subdivision C 4 a, and (ii) such additional factors as the Commission deems necessary to produce such proxy generation rates.

D. In implementing this section, the Commission shall take into consideration the need of default service customers for rate stability and for protection from unreasonable rate fluctuations.

E. On or before July 1, 2004, and annually thereafter, the Commission shall determine, after notice and opportunity for hearing, whether there is a sufficient degree of competition such that the elimination of default service for particular customers, particular classes of customers or particular geographic areas of the Commonwealth will not be contrary to the public interest. The Commission shall report its findings and recommendations concerning modification or termination of default service to the General Assembly and to the Commission on Electric Utility Restructuring, not later than December 1, 2004, and annually thereafter.

F D. A distribution electric cooperative, or one or more affiliates thereof, shall have the obligation and right to be the supplier of default services in its certificated service territory. A distribution electric cooperative's rates for such default services shall be the capped rate for the duration of the capped rate period and shall be based upon the distribution electric cooperative's prudently incurred cost thereafter. Subsections B and C shall not apply to a distribution electric cooperative or its rates. Such default services, for the purposes of this subsection, shall include the supply of electric energy and all services made competitive pursuant to § 56-581.1. If a distribution electric cooperative, or one or more affiliates thereof, elects or seeks to be a default supplier of another electric utility, then the Commission shall designate the default supplier for that distribution electric cooperative, or any affiliate thereof, pursuant to subsection B.

G. To ensure a reliable and adequate supply of electricity, and to promote economic development, an investor-owned distributor that has been designated a default service provider under this section may petition the Commission for approval to construct, or cause to be constructed, a coal-fired generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth, as described in § 15.2-6002, to meet its native load and default service obligations, regardless of whether such facility is located within or without the distributor's service territory. The Commission shall consider any petition filed under this subsection in accordance with its competitive bidding rules promulgated pursuant to § 56-234.3, and in accordance with the provisions of this chapter. Notwithstanding the provisions of subdivision C 3 related to the price of default service, a distributor that constructs, or causes to be constructed, such facility shall have the right to recover the costs of the facility, including allowance for funds used during construction, life-cycle costs, and costs of infrastructure associated therewith, plus a fair rate of return, through its rates for default service. A distributor filing a petition for the construction of a facility under the provisions of this subsection shall file with its application a plan, or a revision to a plan previously filed, as described in subdivision C 3, that proposes default service rates to ensure such cost recovery and fair rate of return. The construction of such facility that utilizes energy resources located within the Commonwealth is in the public interest, and in determining whether to approve such facility, the Commission shall liberally construe the provisions of this title.

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

A. During the first six months of 2009, the Commission shall, after notice and opportunity for hearing, initiate proceedings to review the rates, terms and conditions for the provision of generation, distribution and transmission services of each investor-owned incumbent electric utility. Such proceedings shall be governed by the provisions of Chapter 10 (§ 56-232 et seq.) 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 the following provisions:

1. Rates, terms and conditions for each service shall be reviewed separately on an unbundled basis, and such reviews shall be conducted in a single, combined proceeding. The first such review shall utilize the two successive 12-month test periods ending December 31, 2010. However, the Commission may, in its discretion, elect to stagger its biennial reviews of utilities by utilizing the two successive 12-month test periods ending December 31, 2010, for a Phase I Utility, and utilizing the two successive 12-month test periods ending December 31, 2011, for a Phase II Utility, with subsequent proceedings utilizing the two successive 12-month test periods ending December 31 immediately preceding the year in which such proceeding is conducted. For purposes of this section, a Phase I Utility is an investor-owned incumbent electric utility that was, as of July 1, 1999, not bound by a rate case settlement adopted by the Commission that extended in its application beyond January 1, 2002, and a Phase II Utility is an investor-owned incumbent electric utility that was bound by such a settlement. 

2. Subject to the provisions of subdivision 6, fair rates of return on common equity applicable separately to the generation and distribution services of such utility, and for the two such services combined, shall be determined by the Commission during each such biennial review, as follows:

a. The Commission may use any methodology to determine such return it finds consistent with the public interest, but such return shall not be set lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods for which such data are available by not less than a majority, selected by the Commission as specified in subdivision 2 b, of other investor-owned electric utilities in the peer group of the utility subject to such biennial review, nor shall the Commission set such return more than 300 basis points higher than such average.  

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

c. The Commission may 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, 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. By the same date, each such utility shall also file its plan for its projected generation and transmission requirements to serve its native load for the next 10 years, including how the utility will obtain such resources, the capital requirements for providing such resources, and the anticipated sources of funding for such resources.

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 of providing incentives for the utility to design and operate fair and effective demand-management, conservation, energy efficiency, and load management programs. The Commission shall approve such a petition if it finds that the program is in the public interest and that the need for the incentives is demonstrated with reasonable certainty; provided that the Commission shall allow the recovery of such costs as it finds are reasonable;

c. 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

d. 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 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 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 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.

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

A. As used in this section:

“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.

“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.

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, 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, 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 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. 

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 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.  All incremental costs of the RPS program shall be allocated to and recovered from the utility’s customer classes based on the demand created by the class and within the class based on energy used by the individual customer in the class, except that the incremental costs of the RPS program shall not be allocated to or recovered from customers that are served within the large industrial rate classes of the participating utilities and that are served at primary or transmission voltage.

F.  A utility participating in such program shall apply towards meeting its RPS Goals any renewable energy from existing renewable energy sources owned by the participating utility or purchased as allowed by contract at no additional cost to customers to the extent feasible.  A utility participating in such program shall not apply towards meeting its RPS Goals renewable energy certificates attributable to any renewable energy generated at a renewable energy generation source in operation as of July 1, 2007, that is operated by a person that is served within a utility's large industrial rate class and that is served at primary or transmission voltage.  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.

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

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

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

2.  Each cooperative may, without Commission approval or the requirement of any filing other than as provided in this subdivision, upon an affirmative resolution of its board of directors, increase or decrease all classes of its rates for distribution services at any time, provided, however, that such adjustments will not effect a cumulative net increase or decrease in excess of 5 percent in such rates in any three year period.  Such adjustments will not affect or be limited by any existing fuel or wholesale power cost adjustment provisions.  The cooperative will promptly file any such revised rates with the Commission for informational purposes.

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

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

5. None of the adjustments described in subdivisions 2 through 4 will apply to the rates paid by any customer that takes service by means of dedicated distribution facilities and had noncoincident peak demand in excess of 90 megawatts in calendar year 2006.

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

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

A. As a condition of doing business in the Commonwealth, each person except a default service provider seeking to sell, offering to sell, or selling (i) electric energy to any retail customer in the Commonwealth, on and after January 1, 2002 or (ii) any service that, pursuant to § 56-581.1, may be provided by persons licensed to provide such service, shall obtain a license from the Commission to do so. A license shall not be required solely for the leasing or financing of property used in the sale of electricity to any retail customer in the Commonwealth.

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

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

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

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

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

D. Notwithstanding the provisions of § 13.1-620, a public service company may, through an affiliate or subsidiary, conduct one or more of the following businesses, even if such business is not related to or incidental to its stated business as a public service company: (i) become licensed as a retail electric energy supplier pursuant to this section, or for purposes of participation in an approved pilot program encompassing retail customer choice of electric energy suppliers; (ii) become licensed as an aggregator pursuant to § 56-588, or for purposes of participation in an approved pilot program encompassing retail customer choice of electric energy suppliers; or (iii) become licensed to furnish any service that, pursuant to § 56-581.1, may be provided by persons licensed to provide such service; or (iv) own, manage or control any plant or equipment or any part of a plant or equipment used for the generation of electric energy.

§ 56-589. Municipal and state aggregation.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

C. Whenever pursuant to § 56-581.1 services are made subject to competition, the Commission shall direct the functional separation of such services to the extent necessary to achieve the purposes of this section. Each affected incumbent electric utility shall, by dates prescribed by the Commission, submit for the Commission's approval a plan for such functional separation.

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

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

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

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

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

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

F E. A transaction described in subsection E D shall not:

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

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

G F. Except as provided in subdivision B 5 of § 56-590, nothing in this chapter shall be deemed to abrogate or modify the Commission's authority under Chapter 3 (§ 56-55 et seq.), 4 (§ 56-76 et seq.) or 5 (§ 56-88 et seq.) of this title. However, any person subject to the requirements of subsection E D that is also subject to the requirements of Chapter 5 of this title may be exempted from compliance with the requirements of Chapter 5 of this title.

§ 56-594. Net energy metering provisions.

A. The Commission shall establish by regulation a program, to begin no later than July 1, 2000, which affords eligible customer-generators the opportunity to participate in net energy metering. The regulations may include, but need not be limited to, requirements for (i) retail sellers; (ii) owners and/or operators of distribution or transmission facilities; (iii) providers of default service; (iv) eligible customer-generators; or (v) any combination of the foregoing, as the Commission determines will facilitate the provision of net energy metering, provided that the Commission determines that such requirements do not adversely affect the public interest.

B. For the purpose of this section:

"Eligible customer-generator" means a customer that owns and operates, or contracts with other persons to own, operate, or both, an electrical generating facility that (i) has a capacity of not more than 10 kilowatts for residential customers and 500 kilowatts for nonresidential customers; (ii) uses as its total source of fuel renewable energy, as defined in § 56-576; (iii) is located on the customer's premises and is connected to the customer's wiring on the customer's side of its interconnection with the distributor; (iv) is interconnected and operated in parallel with an electric company's transmission and distribution facilities; and (v) is intended primarily to offset all or part of the customer's own electricity requirements.

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

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

C. The Commission's regulations shall ensure that the metering equipment installed for net metering shall be capable of measuring the flow of electricity in two directions, and shall allocate fairly the cost of such equipment and any necessary interconnection. An eligible customer-generator's electrical generating system shall meet all applicable safety and performance standards established by the National Electrical Code, the Institute of Electrical and Electronics Engineers, and accredited testing laboratories such as Underwriters Laboratories. Beyond the requirements set forth in this section, an eligible customer-generator whose electrical generating system meets those standards and rules shall bear the reasonable cost, if any, as determined by the Commission, to (i) install additional controls, (ii) perform or pay for additional tests, or (iii) purchase additional liability insurance.

D. The Commission shall establish minimum requirements for contracts to be entered into by the parties to net metering arrangements. Such requirements shall protect the customer-generator against discrimination by virtue of its status as a customer-generator. Where electricity generated by the customer-generator over the net metering period exceeds the electricity consumed by the customer-generator, the customer-generator shall not be compensated for the excess electricity unless the entity contracting to receive such electric energy and the customer-generator enter into a power purchase agreement for such excess electricity. The net metering standard contract or tariff shall be available to eligible customer-generators on a first-come, first-served basis in each electric distribution company's Virginia service area until the rated generating capacity owned and operated by eligible customer-generators in the state reaches 0.1 one percent of each electric distribution company's adjusted Virginia peak-load forecast for the previous year.

2.  That §§ 56-581.1 and 56-583 of the Code of Virginia are repealed.

3.  That it is in the public interest, and is consistent with the energy policy goals in § 67-102 of the Code of Virginia, to promote cost-effective conservation of energy through fair and effective demand side management, conservation, energy efficiency, and load management programs, including consumer education.  These programs may include activities by electric utilities, public or private organizations, or both electric utilities and public or private organizations. The Commonwealth shall have a stated goal of reducing the consumption of electric energy by retail customers through the implementation of such programs by the year 2022 by an amount equal to ten percent of the amount of electric energy consumed by retail customers in 2006. The State Corporation Commission shall conduct a proceeding to (i) determine whether the ten percent electric energy consumption reduction goal can be achieved cost-effectively through the operation of such programs, and if not, determine the appropriate goal for the year 2022 relative to base year of 2006, (ii) identify the mix of programs that should be implemented in the Commonwealth to cost-effectively achieve the defined electric energy consumption reduction goal by 2022, including but not limited to demand side management, conservation, energy efficiency, load management, real-time pricing, and consumer education, (iii) develop a plan for the development and implementation of recommended programs, with incentives and alternative means of compliance to achieve such goals, (iv) determine the entity or entities that could most efficiently deploy and administer various elements of the plan, and (v) estimate the cost of attaining the energy consumption reduction goal. The Commission shall, on or before December 15, 2007, submit its findings and recommendations to the Governor and General Assembly, which shall include recommendations for any additional legislation necessary to implement the plan to meet the energy consumption reduction goal. In developing a plan to meet the goal, the Commission may consider providing for a public benefit fund and shall consider the fair and reasonable allocation by customer class of the incremental costs of meeting the goal that are recovered in accordance with subdivision A 5 b of § 56-585.1 of the Code of Virginia.

4.  That the Department of Taxation shall (i) conduct an analysis of the potential implications of the provisions of this act, as compared to previous law, on the system of taxation of the Commonwealth and the revenues generated thereby, and (ii) report its findings and any recommendations with respect thereto to the Commission on Electric Utility Restructuring by November 1, 2007.

5. That nothing in this act shall be deemed to modify or impair the terms, unless otherwise modified by an order of the State Corporation Commission, of any order of the State Corporation Commission approving the divestiture of generation assets that was entered pursuant to § 56-590 of the Code of Virginia.

6. That the Office of Attorney General, in consultation with the State Corporation Commission, shall submit annual reports to the Commission on Electric Utility Restructuring on or before November 1, 2007, and November 1, 2008, in which it shall identify, and recommend appropriate corrective legislation to address, any issues that may impede the implementation of the provisions of this act.

7. That the State Corporation Commission, in consultation with the Office of Attorney General, shall submit a report to the Governor and General Assembly by November 1, 2012, and every five years thereafter, assessing the rates and terms and conditions of incumbent electric utilities in the Commonwealth.  Such report shall include an analysis of, among other matters, the amount, reliability and type of generation facilities needed to serve Virginia native load compared to that available to serve such load, and provide a comparison of such utilities to those in the peer group of such utilities that meet the criteria enumerated in subdivision A 2 of § 56-585.1 of the Code of Virginia.