SEARCH SITE
VIRGINIA LAW PORTAL
- Code of Virginia
- Virginia Administrative Code
- Constitution of Virginia
- Charters
- Authorities
- Compacts
- Uncodified Acts
- RIS Users (account required)
SEARCHABLE DATABASES
- Bills & Resolutions
session legislation - Bill Summaries
session summaries - Reports to the General Assembly
House and Senate documents - Legislative Liaisons
State agency contacts
ACROSS SESSIONS
- Subject Index: Since 1995
- Bills & Resolutions: Since 1994
- Summaries: Since 1994
Developed and maintained by the Division of Legislative Automated Systems.
2009 SESSION
089646340Be it enacted by the General Assembly of Virginia:
1. That §§ 56-585.1 and 56-585.2 of the Code of Virginia are amended and reenacted and that the Code of Virginia is amended by adding sections numbered 10.1-1307.02 and 10.1-1321.2 and by adding in Title 56 a chapter numbered 26, consisting of sections numbered 56-603 through 56-610, as follows:
§ 10.1-1307.02. Permit for generation of electricity during ISO-declared emergency.
A. As used in this section:
"Emergency generation source" means a stationary internal combustion engine that operates according to the procedures in the ISO's emergency operations manual during an ISO-declared emergency.
"ISO-declared emergency" means a condition that exists when the independent system operator, as defined in § 56-576, notifies electric utilities that an emergency exists or may occur and that complies with the definition of "emergency" adopted by the Board pursuant to subsection C.
"Retail customer" has the same meaning ascribed thereto in § 56-576.
B. The Board shall amend its existing regulations governing the issuance of general permits for the use of back-up generation to authorize the construction, installation, reconstruction, modification, and operation of emergency generation sources during ISO-declared emergencies.
C. The Board, in coordination with the ISO, shall adopt by regulation a definition of "emergency" that is compatible with the ISO's emergency operations manual. Except for the adoption of such regulation defining "emergency," the development of the general permit shall be exempt from Article 2 (§ 2.2-4006 et seq.) of the Administrative Process Act.
§ 10.1-1321.2. Determinations regarding clean demand response.
Upon receipt of a request by the State Corporation Commission, the Department shall determine, based upon and subject to the validity of information provided, whether a curtailment of electricity usage or other action by a retail customer constitutes clean demand response. If the Department has not been provided with adequate information to make such a determination, it shall so notify the State Corporation Commission.
§ 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, efficiency of demand response and energy efficiency programs, 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, efficiency of demand response and energy efficiency programs, 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 demand response programs, or
providing incentives for the utility to design and operate fair
and effective demand-management demand management,
conservation, and 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 (i) with
respect to a demand response program,
that the program, including demand response capacity provided to
retail customers through a curtailment service provider pursuant to an ISO
program or a demand response program conducted by the utility, is
authorized pursuant to Chapter 26 (§ 56-603
et seq.), or (ii) with respect
to a demand management,
conservation, or energy
efficiency program,
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, including direct and indirect costs, program
administrative costs and incentives paid to customers who participate, as well
as incentives for the utility, of programs that are approved by the Commission. As
used in this section, "demand response" and "demand
management" have the same meanings ascribed
thereto in § 56-603. The
Commission shall include the enhanced rate of return on common equity
prescribed in subdivision 6 in a rate adjustment clause approved hereunder for
the utility's costs
of designing and operating clean demand
response programs that have the
effect of eliminating the need for construction of new generation facilities. The utility's
costs of designing and operating such
a clean demand
response program that
has the effect of eliminating the need for construction of new generation
facilities shall be treated as a renewable
powered generation facility for
purposes of determining the level of the enhanced
rate of return to be allowed with respect to such costs. A
utility that implements such a clean
demand response program that is treated as a renewable powered generation
facility shall have the right to recover the costs of planning and implementing
the program, including any associated
allowance for funds used during planning and development of the program and costs of equipment
and infrastructure associated therewith, plus, as an
incentive to undertake such programs, an
enhanced rate of return on common equity with respect thereto, to
the same extent as provided with respect to
renewable powered generation facilities under subdivision 6;
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 demand response programs that are authorized to be treated as renewable power generation facilities in clause (ii) of subdivision 6, 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:
"Clean demand response" means a curtailment of electricity consumption or any source of emergency back-up generation that is no more detrimental to air quality than a natural gas-fired peaking electricity generation source of the same capacity, which curtailment or source is certified by the Commission as clean demand response pursuant to subsection D of § 56-609.
"Renewable energy" shall have the same meaning ascribed to it in § 56-576, provided such renewable energy is (i) generated or purchased in the Commonwealth or in the interconnection region of the regional transmission entity of which the participating utility is a member, as it may change from time to time; (ii) generated by a public utility providing electric service in the Commonwealth from a facility in which the public utility owns at least a 49 percent interest and that is located in a control area adjacent to such interconnection region; or (iii) represented by certificates issued by an affiliate of such regional transmission entity, or any successor to such affiliate, and held or acquired by such utility, which validate the generation of renewable energy by eligible sources in such region. "Renewable energy" shall not include electricity generated from pumped storage, but shall include run-of-river generation from a combined pumped-storage and run-of-river facility.
"Total electric energy sold in the base year" means total electric energy sold to Virginia jurisdictional retail customers by a participating utility in calendar year 2007, excluding an amount equivalent to the average of the annual percentages of the electric energy that was supplied to such customers from nuclear generating plants for the calendar years 2004 through 2006.
B. Any investor-owned incumbent electric utility may apply to the Commission for approval to participate in a renewable energy portfolio standard program, as defined in this section. The Commission shall approve such application if the applicant demonstrates that it has a reasonable expectation of achieving 12 percent of its base year electric energy sales from a combination of renewable energy sources and clean demand response 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 or from clean demand response, 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, clean demand response certified by the Commission, 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. A participating utility shall not have the right to recover any costs incurred in connection with clean demand response if, and to the extent that, such costs are recoverable by the utility in connection with its design and operation of a demand response program as provided in to subdivision A 5 b 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.
H. Each investor-owned incumbent electric utility shall report to the Commission annually by November 1 on (i) its efforts, if any, to meet the RPS Goals, (ii) its overall generation of renewable energy, and (iii) advances in renewable generation technology that affect activities described in clauses (i) and (ii).
§ 56-603. Definitions.
As used in this chapter, unless the context requires otherwise:
"Clean demand response" means (i) actions by a retail customer that result in the curtailment of the customer's consumption of electricity as the direct and proximate result of the implementation of an ISO program or a demand response program implemented by an electric utility or (ii) the generation of electricity from a source of emergency back-up generation that is no more detrimental to air quality than a natural gas-fired peaking electricity generation source of the same capacity.
"Curtailment service provider" means a person authorized by an independent system operator to act as an interface party between an independent system operator or an electric utility and a retail customer to deliver demand response capacity.
"Demand management" means a program designed to induce lower electricity use by retail customers at periods when peak demand causes increases in wholesale electricity prices or jeopardizes the reliability of the electric grid, and includes both demand response and time-of-use programs. Demand management includes programs designated as load management programs.
"Demand response" means a program that (i) induces retail customers to curtail electricity usage during periods of congestion and higher prices in the electrical grid by providing real time or near real time information to retail customers who are able to reduce their electricity usage in timely response to such information and (ii) meets the metering and verification policies of the ISO.
"Electric utility" means any distributor, as defined in § 56-576, other than a municipality.
"Independent system operator" or "ISO" has the same meaning ascribed thereto in § 56-576.
"ISO program" means any demand response program conducted by an ISO, including demand response programs under which participating retail customers may receive financial incentives for agreeing to reduce electricity consumption during times of high wholesale market prices or when the reliability of the electric grid is jeopardized.
"Peak demand" means the maximum amount of electric power delivered or required on an electric utility's system at a specific time.
"Retail customer" has the same meaning ascribed thereto in § 56-576.
§ 56-604. Demand response goal established.
A. The Commonwealth hereby establishes the goal of reducing each electric utility's annual peak demand, measured in megawatts, through the implementation of demand response programs by the electric utility or by curtailment service providers operating within electric utility's service territory:
1. By 2015 to an amount that is 5.4 percent less than the electric utility's 2010 annual peak demand; and
2. By 2020 to an amount that is 10.8 percent less than the electric utility's 2010 annual peak demand.
B. The establishment of this goal shall not contravene, but shall supplement, the Commonwealth's goal, set forth in the third enactments of Chapter 888 and Chapter 933 of the Acts of Assembly of 2007, of reducing the consumption of electric energy by retail customers by the year 2022 by an amount equal to 10 percent of the amount of electric energy, measured in megawatt hours, consumed by retail customers in 2006. Demand reduction actions that act to reduce both consumption of electric energy and annual peak demand may be counted toward achieving both goals.
§ 56-605. Demand response planning and reporting.
A. Each electric utility shall file with the Commission, as part of the integrated resource plan that the utility is required to file with the Commission pursuant to subsection B of § 56-599, its plan for attaining the demand response goal set forth in § 56-604. The plan shall include:
1. The electric utility's actual 2008 annual peak demand and the projected annual demand for each year thereafter through and including 2014;
2. A description of the demand response programs that the utility has implemented, or plans to implement, in order to attain the demand response goal set forth in § 56-604; and
3. An identification of any legislative, regulatory, or market barriers to its attainment of the demand response goal set forth in § 56-604.
B. Each electric utility shall prepare biennial updates to its plan to attain the demand response goal. The updates shall be filed biennially with the Commission as part of the updated integrated resource plans that the utility is required to file with the Commission pursuant to subsection C of § 56-599.
C. Each electric utility shall file reports biennially with the Commission that detail the electric utility's efforts in attaining the demand response goal set forth in § 56-604, and the results of such efforts. The reports shall be filed with the updated integrated resource plans that the utility is required to file with the Commission pursuant to subsection C of § 56-599. Each report shall also provide such information as the Commission reasonably may request regarding participation by retail customers in demand response programs and the extent to which the peak demand of the electric utility and of participants, individually and in the aggregate, has been reduced as a result of its programs, ISO programs, and demand response capacity delivered by curtailment service providers.
§ 56-606. ISO members authorized to implement ISO programs.
Any person who is a member of an ISO shall be authorized to deliver, to retail customers located within the area within the Commonwealth that is served by the ISO, products and services directly related to the implementation of an ISO program in accordance with the ISO's policies and procedures.
§ 56-607. Demand response tariff.
A. The Commission shall adopt regulations, pursuant to its rules of practice and procedure, that require each electric utility to offer electric service to all classes of retail customers under a tariff that allows retail customers with access to appropriate communications capabilities to shift or curtail electricity usage in response to dynamic communications. The Commission shall ensure that the terms of the tariff (i) are in 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.
B. Within 120 days following the effective date of the regulations adopted pursuant to subsection A, each electric utility shall submit a demand response tariff that complies with the regulations.
C. The Commission shall, after notice and the opportunity for hearing, determine whether a tariff submitted pursuant to subsection B complies with the regulations adopted pursuant to subsection A. If the tariff is approved, the electric utility shall make electric service available to eligible customers in accordance with the tariff. Eligible customers shall have the option to purchase electric service under such tariff, but shall not be precluded from receiving electric service under any other approved rate, toll, charge, or schedule.
§ 56-608. Virginia Energy Collaborative.
A. The Commission shall reconvene the workgroup initially convened by the Commission in its proceeding in Case No. PUE-2007-00049, which proceeding was conducted pursuant to the third enactments of Chapter 888 and Chapter 933 of the Acts of Assembly of 2007. The reconvened workgroup shall be designated as the Virginia Energy Collaborative.
B. The Virginia Energy Collaborative shall:
1. Review the implementation of the recommendations offered by the workgroup that were included in the Commission's staff's report dated November 16, 2007, in Case No. PUE-2007-00049;
2. Review the implementation of the Virginia Energy Plan prepared pursuant to § 67-201; and
3. Make additional recommendations on issues pertaining to the third enactments of Chapter 888 and Chapter 933 of the Acts of Assembly of 2007 and the Virginia Energy Plan.
C. The Virginia Energy Collaborative shall meet at the call of the Commission, and staffing or support for the Virginia Energy Collaborative shall be provided by the Commission at its discretion.
D. The Virginia Energy Collaborative shall not constitute a collegial body within the executive or legislative branches of state government.
§ 56-609. Certification of clean demand response.
A. The Commission shall adopt regulations that provide procedures and criteria pursuant to which a retail customer may conduct clean demand response, in order that the electric utility serving the retail customer implementing clean demand response may receive credit for the clean demand response under the voluntary renewable energy portfolio standard program pursuant to § 56-585.2. The Commission shall consult with the Department of Environmental Quality in the development of the regulations.
B. By July 1, 2010, the Commission shall implement procedures for the certification of clean demand response.
C. In making any determination regarding a retail customer's implementation of clean demand response, the Commission shall rely upon any determination by the Department of Environmental Quality made pursuant to § 10.1-1321.2.
D. An electric utility shall not receive credit under the voluntary renewable energy portfolio standard program pursuant to § 56-585.2 for a retail customer's implementation of clean demand response until the Commission has certified (i) that the clean demand response complies with the requirements of this chapter and applicable regulations and (ii) the amount of such clean demand response for which the electric utility is entitled to receive credit under the voluntary renewable energy portfolio standard program.
§ 56-610. Reports to Governor and General Assembly.
The Commission shall submit an annual report to the Governor and General Assembly on or before September 1 of each year commencing in 2010 on matters relating to energy efficiency, demand response, and other demand management programs in the Commonwealth. Each report shall also address the Commission's actions relating to energy efficiency, electricity consumption and demand reduction, and conservation of electricity in the Commonwealth. Each report shall also include any recommendations that the Commission deems appropriate to offer for changes in the demand response goal established pursuant to § 56-604 and the consumption reduction goal set forth in the third enactments of Chapter 888 and Chapter 933 of the Acts of Assembly of 2007.
2. That the State Corporation Commission shall conduct a proceeding to evaluate the cost effectiveness of the demand response programs and energy efficiency programs that investor-owned electric utilities make available to their retail customers in the Commonwealth. In conjunction with such proceeding, each investor-owned electric utility shall develop and file with the Commission rate-element-specific marginal cost of service studies, associated avoided cost forecasts for electric supply, and such additional information as the Commission may request regarding metering programs, cost recovery for unamortized investments in meters and other equipment that would be replaced with new advances in demand-side management technology, rate programs, customer incentives, demand response program participation levels, measurement and verification methods or standards, the effectiveness of each demand response program in reducing peak demand, and plans to continue or amend demand response programs. In conducting the evaluation of such programs, the Commission shall (i) analyze the utilities' marginal cost of service studies and avoided cost forecasts; (ii) evaluate how societal benefits may be considered in an evaluation of the cost-effectiveness of demand response programs; and (iii) review programs in operation in other states that provide monetary and other incentives for retail customers to implement demand response measures, including programs that compensate retail customers for the costs of an engineering analysis that identifies potential demand response actions and programs that subsidize the cost of purchasing and installing enabling technology. The Commission shall report its findings and any recommendations, including but not limited to recommendations for cost-effective programs for incentives for utilities to offer and for customers to participate in demand response measures, to the Governor and General Assembly by September 1, 2010.
3. That the State Corporation Commission shall conduct a study of the deployment of, and benefits achieved from, smart meter technologies. The study shall (i) address the deployment of smart meter technologies in other states, (ii) evaluate alternative metering infrastructure, including but not limited to smart meter technology, that will allow electric utilities to communicate to customers of all classes and in all regions of the Commonwealth regarding congestion or grid problems and allow customers to respond by reducing their usage of electricity, (iii) analyze the overall benefits, including improvements in internal operations, that would result from the implementation in the Commonwealth of "smart grid" technologies that provide capabilities and functionality that exceed those provided by smart meter technology and other alternative metering infrastructure, and (iv) estimate the cost of alternatives considered, including cost recovery for unamortized meters and other equipment replaced by such programs. The Commission shall report its findings and any recommendations to the Governor and General Assembly by September 1, 2011.