SB1447: Energy Efficiency Commission; established, report.

SENATE BILL NO. 1447

Offered January 19, 2009
A BILL to amend and reenact §§ 56-576, 56-585.1, 56-585.3, 56-594, 56-597, 59-598, and 56-599 of the Code of Virginia and to amend the Code of Virginia by adding in Chapter 25 of Title 2.2 an article numbered 10, consisting of sections numbered 2.2-2537 through 2.2-2540, by adding a section numbered 56-585.4, and by adding in Chapter 23 of Title 56 a section numbered 56-596.1, relating to electric energy efficiency initiatives; recovery of costs of energy efficiency programs; establishment of the Virginia Energy Efficiency Commission.
Patron-- McEachin

Referred to Committee on Commerce and Labor

Be it enacted by the General Assembly of Virginia:

1.  That §§ 56-576, 56-585.1, 56-585.3, 56-594, 56-597, 59-598, and 56-599 of the Code of Virginia are amended and reenacted and that the Code of Virginia is amended by adding in Chapter 25 of Title 2.2 an article numbered 10, consisting of sections numbered 2.2-2537 through 2.2-2540, by adding a section numbered 56-585.4, and by adding in Chapter 23 of Title 56 a section numbered 56-596.1 as follows:

Article 10.
Virginia Energy Efficiency Commission.

§ 2.2-2537. Virginia Energy Efficiency Commission; purpose.

The Virginia Energy Efficiency Commission (the Commission) is established as an advisory commission in the executive branch of state government. The purpose of the Commission is to evaluate the success of energy efficiency programs proposed or implemented by Virginia's electric utilities, to verify the achievements of such programs, and to identify new cost-effective opportunities for new energy efficiency programs.

§ 2.2-2538. Membership; terms; vacancies; compensation.

A. The Commission shall have a total membership of seven members that shall consist of five nonlegislative citizen members and two ex officio members. Nonlegislative citizen members shall be appointed by the Governor, and shall include at least one representative each from the conservation, public health, consumer advocacy, utility, and manufacturing sectors. The Secretary of Commerce and Trade or his designee and the Governor's Senior Advisor for Energy Policy or his designee shall serve ex officio with voting privileges. Nonlegislative citizen members of the Commission shall be citizens of the Commonwealth. Nonlegislative citizen members shall serve at the pleasure of the Governor, and ex officio members of the Commission shall serve terms coincident with their terms of office. Vacancies shall be filled in the same manner as the original appointments.

B. All members of the Commission shall be reimbursed for all reasonable and necessary expenses incurred in the performance of their duties as provided in §§ 2.2-2813 and 2.2-2825. Funding for the costs of compensation and expenses of the members shall be provided by the Department of Mines, Minerals and Energy. The Commission shall elect a chairman and a vice-chairman from among its members.

§ 2.2-2539. Powers and duties of the Commission.

A. The Commission shall have the power and duty to:

1. Work with Virginia's electric utilities in evaluating the success of energy efficiency programs approved pursuant to § 56-585.4;

2. Verify the progress of Virginia's electric utilities in meeting their energy efficiency goal as provided in integrated resource plans developed in compliance with Chapter 24 (§ 56-597 et seq.) of Title 56;

3. Identify and recommend cost-effective opportunities for the implementation of new energy efficiency measures as they are developed; and

4. Submit to the Governor and the General Assembly an annual report for publication as a report document as provided in the procedures of the Division of Legislative Automated Systems for the processing of legislative documents and reports. The chairman shall submit to the Governor and the General Assembly an annual executive summary of the interim activity and work of the Commission no later than the first day of each regular session of the General Assembly. The executive summary shall be submitted for publication as a report document as provided in the procedures of the Division of Legislative Automated Systems for the processing of legislative documents and reports and shall be posted on the General Assembly's website.

§ 2.2-2540. Staffing.

The Department of Mines, Minerals and Energy shall provide staff support to the Commission. All agencies of the Commonwealth shall provide assistance to the Commission, upon request.

§ 56-576. Definitions.

As used in this chapter:

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

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

"Combined heat and power" means the concurrent production and use of electricity or mechanical power and useful thermal energy for heating, or heating and cooling, from a single fuel source.

"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.

"Demand-side management" means measures to reduce the demand for electricity at any given time by implementation of, among other measures, energy efficiency programs and demand response programs.

"Demand response programs" means programs that induce retail customers to reduce or avoid the consumption of electricity during periods of peak demand, electrical grid congestion, and high prices, by shifting consumption to times of lower demand or temporarily curtailing electricity usage.

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

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

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

"Energy efficiency program" means a program developed and implemented by a utility after July 1, 2009, that is approved by the Commission pursuant to § 56-585.4, and that consists of measures aimed at reducing total electricity consumption by (i) improving devices, systems, or buildings to reduce the amount of energy needed by those devices, systems, or buildings to achieve their intended purpose, (ii) preventing unnecessary use of energy through control modifications, or (iii) changing energy usage behavior.  Energy efficiency programs also include combined heat and power, combined cooling heat and power, and waste heat recovery.  Energy efficiency programs shall not include demand response, curtailment, or other demand-side management programs that do not reduce the total amount of energy used.

"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.

"Municipality" means a city, county, town, authority, or other political subdivision of 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, municipal solid 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.

§ 56-585.1. 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.

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 designing and operating, and providing incentives for the utility to design and operate, fair and effective demand- management, conservation, energy efficiency, and load management programs; however, the costs of a demand response program approved by the Federal Energy Regulatory Commission and administered by the regional transmission entity of which the utility is a member shall not be recoverable under this subdivision if they are recoverable under clause (ii) of subdivision A 4. 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. In addition, the Commission shall approve a petition to allow recovery of costs of an energy efficiency program if it finds that the requirements of subsection D of § 56-585.4 are satisfied.  If the Commission determines it would be just, reasonable, and in the public interest, and in compliance with subsection D of § 56-585.4, the Commission may include the enhanced rate of return on common equity prescribed in subdivision 6 in a rate adjustment clause approved hereunder on capital invested in an energy efficiency program. If the Commission includes such enhanced return on an element of an energy efficiency program in such rate adjustment clause, the element shall be treated as an energy efficiency program described in subdivision 6 for the purposes of this section;

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, or (iv) investments in energy efficiency programs that satisfy, in addition to other any conditions set forth in this section, the requirements of § 56-585.4; 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, or makes an investment in an energy efficiency program, shall have the right to recover the costs of the facility or investment, as accrued against income, through its rates, including projected construction work in progress, and any associated allowance for funds used during construction, planning, deployment, 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. Investments of capital in an energy efficiency program shall not be recovered prior to the date the program is implemented. 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, or energy efficiency program investment, during the first portion of the service life of the facility or energy efficiency program investment. 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 or energy efficiency program investment, 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 or energy efficiency program investment may be in meeting the energy needs of the citizens of the Commonwealth and the risks involved in the development of the facility or the implementation of the energy efficiency program. After the first portion of the service life of the facility or energy efficiency program investment is concluded, the utility's general rate of return shall be applied to such facility or energy efficiency program investment 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, or in the case of an investment in an element of an energy efficiency program, when the element's implementation commences, and such service life shall be deemed equal in years to the life of that facility or energy efficiency program investment 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 or energy efficiency program investment 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 or energy efficiency program investment's service life to which such enhanced rate of return shall be applied, shall vary by type of facility or energy efficiency program investment, 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  Energy efficiency program      200            Between 3 and 7 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 or energy efficiency program investments 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 or energy efficiency program investments 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 or energy efficiency program investments 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 or energy efficiency program investments 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 or energy efficiency program investments 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 or energy efficiency program investments 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.

§ 56-585.3. 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, including any costs incurred in implementing energy efficiency programs pursuant to § 56-585.4.

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.

§ 56-585.4. Energy efficiency programs.

A. By January 1, 2010, the Commission shall adopt regulations that establish minimum requirements for energy efficiency programs for incumbent investor-owned electric utilities and electric cooperatives. The regulations shall require that each incumbent electric utility establish an energy efficiency program under which the utility shall invest in efforts to reduce the total electricity consumption of its retail customers. The regulations also shall (i) provide for a utility to recover approved costs developing and implementing its energy efficiency program pursuant to a rate adjustment clause as provided in subdivision A 5 and, if the utility is an investor-owned utility, in subdivision A 6 of § 56-585.1 and (ii) coordinate the Commission's approval of a utility's energy efficiency program with the portion of the utility's integrated resource plan that addresses reducing the consumption of electricity by the utility's retail customers pursuant to subsection E of § 56-599. Elements of each utility's energy efficiency program shall include, at a minimum:

1. Incentives for retail customers to purchase energy-efficient products;

2. Energy audits provided by the utility that identify opportunities for reducing energy use;

3. Grants or loans to provide retail customers with funding needed to implement the recommendations of such an energy audit;

4. Incentives for improvements in industrial processes;

5. Incentives and other measures for improving the energy efficiency of building envelopes, which may include weatherization of residential buildings;

6. Incentives and other measures for improving the energy efficiency of heating, ventilation, and air conditioning systems;

7. Incentives and other measures for improving the energy efficiency of commercial and industrial lighting and appliances; and

8. A standard-offer program pursuant to which the utility purchases verified energy savings from industrial customers under a tariff to be approved by the Commission that establishes a price, on a per-kilowatt hour basis, for electricity saved as a part of the utility's integrated resource plan submitted pursuant to Chapter 24 (§ 56-597 et seq.).

An energy efficiency program shall not include demand response programs that are designed to shift electricity consumption from times of peak demand or price but not necessarily to reduce the total amount of electricity consumed over time.

B. By September 1, 2010, each incumbent electric utility shall file a proposed energy efficiency program with the Commission, which plan shall comply with the regulations of the Commission adopted pursuant to subsection A.

C. The Commission shall analyze and review a proposed energy efficiency program and, after giving notice and opportunity to be heard, the Commission shall approve a proposed energy efficiency program if it finds that the proposed program (i) complies with the regulations of the Commission adopted pursuant to subsection A and is in the public interest and (ii) offers, at a minimum, each element of an energy efficiency program identified in subdivisions A 1 through A 8.

D. An incumbent electric utility may recover costs incurred in implementing its energy efficiency program through a rate adjustment clause as provided in subdivision A 5 of § 56-585.1, with the enhanced rate of return on equity for investor-owned electric utilities as provided in subdivision A 6 of § 56-585.1, if:

1. The elements of its energy efficiency program achieve quantifiable and observable reductions in the total electricity consumption of the utility's retail customers over time;

2. The scope of the elements of the energy efficiency program is sufficient to reduce the consumption of electricity by the utility's retail customers to such an extent that the quantity of electricity consumed by the utility's retail customers in 2025 will be 19 percent less than the quantity forecasted for 2025, which forecasted quantity has been projected as provided in subdivision E 1 of § 56-599; and

3. All classes of the utility's retail customers, including commercial, industrial, churches, and government customers and those residential customers who are ineligible to participate in the Weatherization Assistance Program administered by the Department of Housing and Community Development and receiving funding through the Low Income Home Energy Assistance Program (LIHEAP) Block Grant, have been provided adequate opportunity to participate in applicable elements of the energy efficiency program.

§ 56-594. Net energy metering.

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. In addition, the Commission's regulations shall provide that eligible customer-generators that participate in net energy metering are eligible for investments in energy efficiency resources as defined in § 56-597, in order to ensure that the Commonwealth's net energy metering program supplements each utility's energy efficiency programs.

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.

E. If electricity generated by an eligible customer-generator over the net metering period exceeds the electricity consumed by the customer-generator, the customer-generator shall be compensated for the excess electricity if the entity contracting to receive such electric energy and the customer-generator enter into a power purchase agreement for such excess electricity. If the eligible customer-generator receives generation service from a default service provider, the default service provider, upon the written request of the customer-generator, shall enter into a power purchase agreement with the requesting eligible customer-generator that is consistent with the minimum requirements for contracts established by the Commission pursuant to subsection D. The power purchase agreement shall obligate the default service provider to purchase such excess electricity at the rate that is provided for such purchases in a net metering standard contract or tariff approved by the Commission, unless the parties agree to a higher rate. The 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 one percent of each electric distribution company's adjusted Virginia peak-load forecast for the previous year, and shall require the default service provider to pay the eligible customer-generator for such excess electricity in a timely manner at a rate to be established by the Commission.

§ 56-596.1. Access to grid for backup generation.

The Commission shall establish by regulation a program, to begin no later than July 1, 2010, that affords distributed generators access to the electrical grid. The purpose of such regulations shall be to encourage the development of distributed generation facilities that increase an electric utility's energy efficiency through implementation of combined heat and power. The regulations may include, but need not be limited to, requirements for (i) investor owned electric utilities and electric cooperatives; (ii) owners and operators of transmission facilities; (iii) owners and operators of distributed cogeneration facilities; or (iv) any combination of the foregoing, as the Commission determines will facilitate access to the electrical grid by distributed generation facilities, provided that the Commission determines that such requirements do not adversely affect the public interest.

§ 56-597. Definitions.

As used in this chapter:

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

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

"Electric utility" means any investor-owned public utility or cooperative that provides electric energy for use by retail customers.

"Energy efficiency resources" means measures aimed at reducing total electricity consumption by (i) improving devices, systems, or buildings to reduce the amount of energy needed by those devices, systems, or buildings to achieve their intended purpose, (ii) preventing unnecessary use of energy through control modifications, or (iii) changing energy usage behavior.  Energy efficiency resources also include combined heat and power, combined cooling heat and power, and waste heat recovery.  Energy efficiency resources shall not include demand response, curtailment, or other demand-side management programs that do not reduce the total amount of energy used.

"Integrated resource plan" or "IRP" means a document developed by an electric utility that provides a forecast of its load obligations and a plan to meet those obligations by supply side and demand side resources over the ensuing 15 years to promote reasonable prices, reliable service, energy independence, and environmental responsibility.

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

§ 56-598. Contents of integrated resource plans.

A. An IRP should:

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

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

b. Purchasing electricity from affiliates and third parties; and

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

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

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

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

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

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

B. An IRP, including any update thereto, shall include a description of the electric utility's investments in energy efficiency resources that have been made in implementing the utility's energy efficiency program developed pursuant to § 56-585.4, including an analysis of the effectiveness of such programs in meeting the utility's plan, described in subdivision E 2 of § 56-599, to reduce consumption by its retail customers.

§ 56-599. Integrated resource plan required.

A. Not later than December 31, 2008, the Commission shall order each electric utility to develop an integrated resource plan. The order may establish guidelines for developing an IRP.

B. By September 1, 2009, each electric utility shall file an initial integrated resource plan with the Commission, which plan shall comply with the provisions of the order of the Commission issued pursuant to subsection A.

C. Each electric utility shall file an updated integrated resource plan at least every two years thereafter, which plan shall comply with the provisions of any relevant order of the Commission establishing guidelines for the format and contents of updated and revised integrated resource plans.

D. In preparing an integrated resource plan, each electric utility shall systematically evaluate, and may propose:

1. Entering into short-term and long-term electric power purchase contracts;

2. Owning and operating electric power generation facilities;

3. Building new generation facilities;

4. Relying on purchases from the short term or spot markets;

5. Making investments in demand-side resources, including energy efficiency and demand-side management services;

6. Taking such other actions, as the Commission may approve, to diversify its generation supply portfolio and ensure that the electric utility is able to implement an approved plan; and

7. The methods by which the electric utility proposes to acquire the supply and demand resources identified in its proposed integrated resource plan.

E. Each integrated resource plan shall include:

1. A forecast of the quantity of electricity that will be consumed by the electric utility's retail customers in the aggregate in calendar year 2025, which forecast shall be based on actual consumption in 2007 with an average annual growth rate between 2008 and 2025 of 1.4 percent;

2. A plan to reduce the consumption of electricity by the utility's retail customers in order that the quantity of electricity consumed by the utility's retail customers in 2025 will be 19 percent less than the quantity forecasted for 2025, which forecasted quantity has been projected as provided in subdivision 1; and

3. The utility's schedule for investing in energy efficiency resources, including implementation of its energy efficiency program under § 56-585.4, and projections of how such investments will result in the utility's attainment of the reduction in consumption described in subdivision 2.

Each updated integrated resource plan shall describe (i) the electric utility's current and planned investments in energy efficiency resources, including the implementation of its energy efficiency program under § 56-585.4; (ii) the electric utility's progress in implementing its plan to achieve the consumption reduction as described in subdivision 2; and (iii) the status and effectiveness of its investments in energy efficiency resources, including each element of its energy efficiency program under § 56-585.4.

F. The Commission shall analyze and review an integrated resource plan and, after giving notice and opportunity to be heard, the Commission shall make a determination as to whether an IRP is reasonable and is in the public interest. If, after notice and hearing, the Commission determines that an electric utility is not in compliance with its approved schedule for investing in energy efficiency resources under subdivision E 3, the Commission shall order the utility to make an alternative compliance payment.  Alternative compliance payments shall be assessed at a rate of $0.03 for every kilowatt hour by which consumption of electric energy by its retail customers in such year exceeds the amount forecasted in subdivision E 2.  Alternative compliance payments collected pursuant to this section shall be paid into the Virginia Energy Efficiency and Integrated Resource Plan Compliance Fund created pursuant to subsection G.

G.  There is hereby established a special fund in the state treasury to be known as the Virginia Energy Efficiency and Integrated Resource Plan Compliance Fund (the Fund), which shall be administered by the Department of Mines, Minerals, and Energy.  The Fund shall include all alternative compliance payments collected by the Commission through its oversight of Integrated Resource Plans, pursuant to subsection F, and such moneys as may be appropriated by the General Assembly or contributed from any other source from time to time and designated for the Fund.  The Fund shall be used solely for the payment of financial incentives, including grants and low-interest loans, to persons other than utilities for the implementation of energy efficiency and conservation programs.  Unallocated moneys in the Fund in any year shall remain in the Fund and be available for allocation for grants under this section in ensuing fiscal years.