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2007 SESSION

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SB 1416 Electric utility service; advances scheduled expiration of capped rate period.

Introduced by: Thomas K. Norment, Jr. | all patrons    ...    notes | add to my profiles | history

SUMMARY AS ENACTED WITH GOVERNOR'S RECOMMENDATION:

Electric utility regulation. Advances the scheduled expiration of the capped rate period from December 31, 2010, to December 31, 2008, establishes a new mechanism for regulating the rates of investor-owned electric utilities, and limits the ability of most consumers to purchase electric generation service from competing suppliers. The ratemaking procedure requires the State Corporation Commission (SCC) to conduct a rate case for investor-owned utilities in 2009; thereafter, the SCC will review each utility's rates, terms, and conditions using two 12-month test periods ending December 31, 2010, though the SCC is given discretion to stagger the years in which it conducts such reviews.  In these biennial reviews the SCC will determine fair rates of return on common equity for the utility's generation and distribution services, using any methodology it finds consistent with the public interest.  However, the return shall not be set: (i) lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods by a peer group of a majority of the other vertically-integrated investor-owned electric utilities in the southeastern United States with a Moody's bond rating of at least Baa or (ii) higher than 300 basis points above that average.  Increases in the rate of return are capped based on the rate of increases in the Consumer Price Index (CPI). The SCC may increase or decrease the rate of return by a Performance Incentive of up to 100 basis points based on the generating plant performance, customer service, operations and efficiency of a utility. In setting the return on equity, the SCC is required to 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. If the combined rate of return on common equity earned is no more than one half of one percent above or below this rate of return, the return shall not be considered either excessive or insufficient. Each utility may seek rate adjustment clauses to recover (i) costs for transmission services provided by PJM Interconnection under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission (FERC) and costs of FERC-approved demand response programs; (ii) deferred environmental and reliability costs authorized under prior capped rate rules; (iii) costs of providing incentives for the utility to design and operate fair and effective demand-management, conservation, energy efficiency, and load management programs; (iv) costs of participation in the new renewable energy portfolio standard program; and (v) costs of projects that the SCC 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, which costs may include the enhanced rate of return for new base load generation if the project would reduce the need for construction of new generation facilities by enabling the continued operation of existing generation facilities. A utility may also apply a rate adjustment clause for recovery from customers of the costs of (i) a coal-fired generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth, (ii) one or more other generation facilities, or (iii) one or more major unit modifications of generation facilities, to meet the utility’s projected native load obligations. The utility may recover an enhanced rate of return on common equity associated with the type of project, which may include projects utilizing nuclear power, renewable technologies, carbon capture facilities, combined cycle combustion turbines, and conventional coal facilities. The period over which the enhanced rate of return may be collected depends on the type of facility, as determined by the SCC within specified ranges. The SCC’s final order on any petition filed for any of the rate adjustment clauses shall be entered within a specified period after the filing of the petition, and any rate increase required by the clause shall go into effect within 60 days or upon the end of capped rates, whichever is later. The SCC is required to consider petitions for rate adjustment clauses on a stand-alone basis, without regard to the other costs or revenues of the utility. The enhanced returns are subject to revocation if permits are not applied for or construction is not commenced by specified dates. If the SCC determines in a biennial review that a utility underearned by at least 50 basis points on its generation and distribution services, excluding provisions for new generation facilities, the SCC is required to increase the utility’s rates to a level necessary to provide the opportunity to fully recover the costs of providing the utility’s services and to earn such fair rate of return. If the SCC determines in a biennial review that a utility earned more than 50 basis points above a fair combined rate of return on its generation and distribution services, excluding provisions for new generation facilities, the SCC is required to direct that 60 percent of such overearnings be credited to customers' bills over a period of between 6 and 12 months, to be determined by the SCC. In addition, if the SCC determines that the utility's earnings exceed this limit for two consecutive biennial review periods, it shall also order reductions to the utility’s rates, provided that rates may not be reduced to levels below what would provide the utility with the opportunity to fully recover its costs and to earn a fair combined rate of return on its generation and distribution services, excluding provisions for new generation facilities. If the Commission determines that and the utility's total aggregate regulated rates would exceed the annual increases in CPI, when compared to the utility's rates as determined in the biennial review for a base period (either the utility's first test period or the most recent test period for which credits are applied to customers' bills), the Commission shall direct, unless such action would not be in the public interest, that any or all of such overearnings be credited to customers' bills. An electric utility that demonstrates that it has a reasonable expectation of achieving 12 percent of its base year electric energy sales from certain renewable energy sources during calendar year 2022 may participate in a renewable energy portfolio standard program. Under the program, a participating utility that meets specified percentage goals for sales of eligible renewable energy is eligible for a Performance Incentive that increases the fair combined rate of return on common equity for the utility by a 50 basis points through the third succeeding biennial review if it continues to meet the RPS Goals. It is also entitled to an enhanced rate of return on the costs associated with the construction of renewable energy generation facilities used to provide the renewable energy. Participating utilities may recover their incremental costs of meeting the RPS Goals from customers other than large industrial customers purchasing electricity at large general service rates and at primary or transmission voltage. Double credits will be provided for energy from solar or wind sources. Specific provisions address the use of certain wood products for projects qualifying to meet the renewable energy goals. With regard to the ability of customers to purchase generation services from competing providers, the measure provides that after the capped rate period ends, only customers whose annual demand exceeds five megawatts will be permitted to shop.  However, two or more individual nonresidential retail customers may aggregate their demand for the purpose of meeting the five megawatt threshold if the Commission finds that neither their incumbent electric utility nor its retail customers will be adversely affected and that the demand of the customers who are allowed to buy power from competitors will not exceed one percent of the utility’s peak annual load.  Aggregating customers may petition the SCC to aggregate their supply, even if their aggregated load exceeds 1% of the utility’s demand, if the aggregation would not harm other utility customers or the utility. The ability of large customers to purchase electric power from a licensed competitive supplier is subject to the condition that they cannot thereafter purchase electricity from their incumbent utility without giving 5 years’ notice, with certain exceptions; however, the 5-year notice requirement does not apply if the SCC finds that waiving it would not harm other utility customers or the utility. Municipalities are allowed to aggregate the electric energy load of their governmental operations for the purpose of negotiating rates and terms, and conditions of service from the electric utility certificated by the Commission to serve the territory in which such operations are located. Other provisions (i) require the deferral over the period 2008-2010 of a portion of Dominion's 2007 fuel factor increase; (ii) authorize electric utilities to seek approval of optional performance-based regulation methodologies to the same extent as gas utilities; (iii) require that 75 percent of the margins from off-system sales be applied to the utility's fuel expenses unless the SCC finds by clear and convincing evidence that a smaller percentage is in the public interest; (iv) require rates of distribution electric cooperatives to be regulated pursuant to the provisions of Chapters 9.1 and 10 of Title 56, subject to the ability to increase rates without SCC approval by not more than five percent over three years and to make certain other changes to terms and conditions of service; (v) provide that the measure does not modify or impair the terms, unless otherwise modified by an order of the SCC, of any SCC order approving the divestiture of generation assets; (vi) direct the SCC to complete by December 15, 2007, a proceeding to develop a plan to identify and implement demand side management, conservation, energy efficiency, load management, real-time pricing, and consumer education programs in order to achieve by 2022 a stated goal of reducing the consumption of electric energy by retail customers by ten percent of the amount consumed by such customers in 2006; (vii) direct the Office of the Attorney General to identify issues of the act that impede its implementation; (viii) direct the Department of Taxation is directed to conduct an analysis of the potential implications of the provisions of this measure on the system of taxation; (ix) ensure that utilities use competitive bidding in purchasing and construction practices; (x) increase the cap on power that a utility may be required to purchase from eligible customer-generators under the net energy metering program from 0.1% to one percent of the utility's adjusted peal load; and (xi) allow competitive service providers to offer 100% renewable power to retail customers in any area of the Commonwealth where the customer's incumbent utility does not offer such a tariff. Provisions of the Electric Utility Restructuring Act that exempt the generation of electric energy from regulation, prohibit public service corporations from exercising the power of eminent domain to acquire property for generation facilities, authorize the collection of wires charges, and authorize competition for metering and billing services are repealed. This bill is identical to HB 3068.

SUMMARY AS PASSED:

Electric utilities. Advances the scheduled expiration of the capped rate period from December 31, 2010, to December 31, 2008, establishes a new mechanism for regulating the rates of investor-owned electric utilities, and limits the ability of most consumers to purchase electric generation service from competing suppliers.  The ratemaking procedure requires the State Corporation Commission (SCC) to conduct a rate case for investor-owned utilities in 2009; thereafter, the SCC will review each utility's rates, terms, and conditions using two 12-month test periods ending December 31, 2010, though the SCC is given discretion to stagger the years in which it conducts such reviews.  In these biennial reviews the SCC will determine fair rates of return on common equity for the utility's generation and distribution services, using any methodology it finds consistent with the public interest.  However, the return shall not be set: (i) lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods by a peer group of a majority of the other vertically-integrated investor-owned electric utilities in the southeastern United States with a Moody's bond rating of at least Baa or (ii) higher than 300 basis points above that average.  Increases in the rate of return are capped based on the rate of increases in the Consumer Price Index (CPI). The SCC may increase or decrease the rate of return by a Performance Incentive of up to 50 basis points based on the generating plant performance, customer service, operations and efficiency of a utility. If the combined rate of return on common equity earned is no more than one half of one percent above or below this rate of return, the return shall not be considered either excessive or insufficient.  Each utility may seek rate adjustment clauses to recover (i) costs for transmission services provided by PJM Interconnection under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission (FERC) and costs of FERC-approved demand response programs; (ii) deferred environmental and reliability costs authorized under prior capped rate rules; (iii) costs of providing incentives for the utility to design and operate fair and effective demand-management, conservation, energy efficiency, and load management programs; (iv) costs of participation in the new renewable energy portfolio standard program; and (v) 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, which costs may include the enhanced rate of return for new base load generation if the project would reduce the need for construction of new generation facilities by enabling the continued operation of existing generation facilities.  A utility may also apply a rate adjustment clause for recovery from customers of the costs of (i) a coal-fired generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth, (ii) one or more other generation facilities, or (iii) one or more major unit modifications of generation facilities, to meet the utility’s projected native load obligations.  The utility may recover an enhanced rate of return on common equity associated with the type of project, and the period over which the enhanced rate of return may be collected depends on the type of facility, as determined by the Commission within specified ranges.  The Commission’s final order on any petition filed for any of the rate adjustment clauses shall be entered within a specified period after the filing of the petition, and any rate increase required by the clause shall go into effect within 60 days or upon the end of capped rates, whichever is later.  The Commission is required to consider petitions for rate adjustment clauses on a stand-alone basis, without regard to the other costs or revenues of the utility.  The enhanced returns are subject to revocation if permits are not applied for or construction is not commenced by specified dates.  If the Commission determines in a biennial review that a utility underearned by at least 50 basis points on its generation and distribution services, excluding provisions for new generation facilities, the Commission is required to increase the utility’s rates to a level necessary to provide the opportunity to fully recover the costs of providing the utility’s services and to earn such fair rate of return. If the Commission determines in a biennial review that a utility earned more than 50 basis points above a fair combined rate of return on its generation and distribution services, excluding provisions for new generation facilities, the Commission is required to direct that 60 percent of such overearnings be credited to customers' bills.  In addition, if the Commission determines that (i) the utility's earnings exceed this limit for two consecutive biennial review periods, the Commission shall also order reductions to the utility’s rates, provided that rates may not be reduced to levels below what would provide the utility with the opportunity to fully recover its costs and to earn a fair combined rate of return on its generation and distribution services, excluding provisions for new generation facilities and (ii) the utility's total aggregate regulated rates would exceed the annual increases in CPI, when compared to the utility's rates as determined in the biennial review for a base period (either the utility's first test period or the most recent test period for which credits are applied to customers' bills), the Commission shall direct, unless such action would not be in the public interest, that any or all of such overearnings be credited to customers' bills.  An electric utility that demonstrates that it has a reasonable expectation of achieving 12 percent of its base year electric energy sales from renewable energy sources during calendar year 2022 may participate in a renewable energy portfolio standard program. Under the program, a participating utility that meets specified percentage goals for sales of renewable energy is eligible for a Performance Incentive that increases the fair combined rate of return on common equity for the utility by a 50 basis points through the third succeeding biennial review if it continues to meet the RPS Goals. It is also entitled to an enhanced rate of return on the costs associated with the construction of renewable energy generation facilities used to provide the renewable energy.  Double credits will be provided for energy from solar or wind sources.  Specific provisions address the use of certain wood products for projects qualifying to meet the renewable energy goals. With regard to the ability of customers to purchase generation services from competing providers, the measure provides that after the capped rate period ends, only customers whose annual demand exceeds five megawatts will be permitted to shop, and the load of the switching customers does not exceed one percent of the utility's load.  However, two or more individual nonresidential retail customers may aggregate their demand for the purpose of meeting the five megawatt threshold if the Commission finds that neither their incumbent electric utility nor its retail customers will be adversely affected and that the demand of the customers who are allowed to buy power from competitors will not exceed one percent of the utility’s peak annual load. The ability of large customers to purchase electric power from a licensed competitive supplier is subject to the condition that they cannot thereafter purchase electricity from their incumbent utility without giving 5 years’ notice, with certain exceptions. Municipalities are allowed to aggregate the electric energy load of their governmental operations for the purpose of negotiating rates and terms, and conditions of service from the electric utility certificated by the Commission to serve the territory in which such operations are located. Other provisions (i) require the deferral over the period 2008-2010 of a portion of Dominion's 2007 fuel factor increase; (ii) authorize electric utilities to seek approval of optional performance-based regulation methodologies to the same extent as gas utilities; (iii) require that 75 percent of the margins from off-system sales be applied to the utility's fuel expenses unless the SCC finds by clear and convincing evidence that a smaller percentage is in the public interest; (iv) require rates of distribution electric cooperatives to be regulated pursuant to the provisions of Chapters 9.1 and 10 of Title 56, subject to the ability to increase rates without SCC approval by not more than five percent over three years and to make certain other changes to terms and conditions of service; (v) provide that the measure does not modify or impair the terms, unless otherwise modified by an order of the SCC, of any SCC order approving the divestiture of generation assets; (vi) direct the SCC to conduct a proceeding to establish goals for the amount of energy and demand to be reduced by the operation of demand side management, conservation, energy efficiency, and load management programs, and develop a plan for the development and implementation of recommended programs; (vii) direct the Office of the Attorney General to identify issues of the act that impede its implementation; and (viii) direct the Department of Taxation is directed to conduct an analysis of the potential implications of the provisions of this measure on the system of taxation. Provisions of the Electric Utility Restructuring Act that exempt the generation of electric energy from regulation, prohibit public service corporations from exercising the power of eminent domain to acquire property for generation facilities, authorize the collection of wires charges, and authorize competition for metering and billing services are repealed. This bill is identical to HB 3068.

SUMMARY AS PASSED SENATE:

Electric utilities.  Advances the scheduled expiration of the capped rate period from December 31, 2010, to December 31, 2008, establishes a new mechanism for regulating the rates of investor-owned electric utilities, and ends the ability of most consumers to shop for electric generation service. The ratemaking procedure requires the State Corporation Commission (SCC) to review each utility's rates, terms, and conditions using a 12-month test period ending December 31, 2008 (for utilities other than Dominion) and the two successive 12-month test periods ending December 31, 2009 (for Dominion). Thereafter, the reviews will cover the two successive 12-month test periods.  In these biennial reviews the SCC will determine fair rates of return on common equity for the utility's generation and distribution services, using any methodology it finds consistent with the public interest.  However, the return shall not be set: (i) lower than the average of the returns on common equity reported to the Securities and Exchange Commission for the three most recent annual periods by a peer group of a majority of the other vertically-integrated investor-owned electric utilities in the southeastern United States with a Moody's bond rating of at least Baa or (ii) higher than 300 basis points above that average. The SCC may increase or decrease the rate of return by a Performance Incentive of up to 50 basis points based on the generating plant performance, customer service, operations and efficiency of a utility. If the combined rate of return on common equity earned is no more than one half of one percent above or below this rate of return, the return shall not be considered either excessive or insufficient. Each utility may seek rate adjustment clauses to recover (i) costs for transmission services provided by PJM Interconnection under applicable rates, terms and conditions approved by the Federal Energy Regulatory Commission (FERC) and costs of FERC-approved demand response programs; (ii) deferred environmental and reliability costs authorized under prior capped rate rules; (iii) costs of providing incentives for the utility to design and operate fair and effective demand-management, conservation, energy efficiency, and load management programs; (iv) costs of participation in the new renewable energy portfolio standard program; and (v) 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, which costs may include the enhanced rate of return for new base load generation if the project would reduce the need for construction of new generation facilities by enabling the continued operation of existing generation facilities.  A utility may also apply a rate adjustment clause for recovery from customers of the costs of (i) a coal-fired generation facility that utilizes Virginia coal and is located in the coalfield region of the Commonwealth, (ii) one or more other generation facilities, or (iii) one or more major unit modifications of generation facilities, to meet the utility’s projected native load obligations.  The utility may recover an enhanced rate of return on common equity associated with the project of between 200 and 300 basis points, as determined by the Commission, on projects and facilities other than simple-cycle combustion turbine facilities. This enhanced rate of return is applied during the first half of the life of the project.  The Commission’s final order on any petition filed for any of the rate adjustment clauses shall be entered within a specified period after the filing of the petition, and any rate increase required by the clause shall go into effect within 60 days or upon the end of capped rates, whichever is later.  The Commission is required to consider petitions for rate adjustment clauses on a stand-alone basis, without regard to the other costs or revenues of the utility.  Costs incurred prior to the filing of a petition for a rate adjustment clause, or during the petition's consideration, that relate to recover of the deferred environmental and reliability costs or to new generation facilities and projects (other than those using simple-cycle combustion turbines) will be deferred until the later of Commission’s final order or the implementation of any rate adjustment clauses. This deferral provision does not affect the rights of parties with respect to FERC proceeding regarding Dominion's proposed deferral of its costs of joining PJM. If the Commission determines in a biennial review that a utility underearned by at least 50 basis points on its generation and distribution services, excluding provisions for new generation facilities, the Commission is required to increase the utility’s rates to a level necessary to provide the opportunity to fully recover the costs of providing the utility’s services and to earn such fair rate of return.  The most recent 12-month test period will be used in determining the amount of the rate increase. If the Commission determines in a biennial review that a utility earned more than 50 basis points above a fair combined rate of return on its generation and distribution services, excluding provisions for new generation facilities, the Commission is required to direct that 60 percent of such overearnings be credited to customers' bills.  In addition, if the Commission determines that (i) the utility's earnings exceed this limit for two consecutive biennial review periods, the Commission shall also order reductions to the utility’s rates, provided that rates may not be reduced to levels below what would provide the utility with the opportunity to fully recover its costs and to earn a fair combined rate of return on its generation and distribution services, excluding provisions for new generation facilities and (ii) the utility's total aggregate regulated rates, following a biennial review, would exceed the annual increases in CPI, when compared to the utility's rates as determined in the biennial review for a base period (either the utility's first test period or the most recent test period for which credits are applied to customers' bills), the Commission shall direct, unless such action would not be in the public interest, that any or all of such overearnings be credited to customers' bills, in lieu of any rate reduction or other crediting. An electric utility that demonstrates that it has a reasonable expectation of achieving 12 percent of its base year electric energy sales from renewable energy sources during calendar year 2022 may participate in a renewable energy portfolio standard program. Under the program, a participating utility that meets specified percentage goals for sales of renewable energy is eligible for a Performance Incentive that increases the fair combined rate of return on common equity for the utility by a 50 basis points through the third succeeding biennial review if it continues to meet the RPS Goals. It is also entitled to an enhanced rate of return on the costs associated with the construction of renewable energy generation facilities used to provide the renewable energy. With regard to the ability of customers to purchase generation services from competing providers, the measure provides that after the capped rate period ends, only customers whose annual demand exceeds five megawatts will be permitted to shop. However, two or more individual nonresidential retail customers may aggregate their demand for the purpose of meeting the 5 megawatt threshold if the Commission finds that neither their incumbent electric utility nor its retail customers will be adversely affected and that the demand of the customers who are allowed to buy power from competitors will not exceed one percent of the utility’s peak annual load. The ability of large customers to purchase electric power from a licensed competitive supplier is subject to the condition that they cannot thereafter purchase electricity from their incumbent utility without giving 5 years’ notice, with certain exceptions. Municipalities are allowed to aggregating the electric energy load of their governmental operations for the purpose of negotiating rates and terms, and conditions of service from the electric utility certificated by the Commission to serve the territory in which such operations are located.  Other provisions (i) require utilities to file plans for how they will meet generation and transmission requirements to serve native load for the ensuing 10 years; (ii) authorize electric utilities to seek approval of optional performance-based regulation methodologies to the same extent as gas utilities; (iii) restore the requirement that the Commission find, before permitting the construction and operation of an electrical generating facility, that the facility is required by the public convenience and necessity; (iv) require rates of distribution electric cooperatives to be regulated pursuant to the provisions of Chapters 9.1 and 10 of Title 56; (v) state that it does not impair the terms, unless otherwise modified by an order of the SCC, of any order approving the divestiture of generation assets; (vi) provide that an incumbent electric utility that transferred all of its generating assets to an affiliate shall, by January 1, 2009 purchase generating assets or notify the SCC of its intent in good faith to pursue the construction of generating assets to serve the base load portion of its retail native load in Virginia, and that after that date its rates, terms and conditions shall be determined in the same manner as other electric utilities; (vii) direct the SCC to conduct a proceeding to establish goals for the amount of energy and demand to be reduced by the operation of demand side management, conservation, energy efficiency, and load management programs, and develop a plan for the development and implementation of recommended programs; and (viii) direct the Department of Taxation is directed to conduct an analysis of the potential implications of the provisions of this measure on the system of taxation. Provisions of the Electric Utility Restructuring Act that exempt the generation of electric energy from regulation, prohibit public service corporations from exercising the power of eminent domain to acquire property for generation facilities, and authorize competition for metering and billing services are repealed. 

SUMMARY AS INTRODUCED:

Electric utilities.  Advances the scheduled expiration of the capped rate period from December 31, 2010, to December 31, 2008, and establishes a new methodology for determining electric rates for investor-owned electric utilities after the expiration or termination of capped rates.  After the expiration or termination of capped rates, the State Corporation Commission (SCC) is required to conduct biennial reviews of the rates for generation, distribution and transmission services, on an unbundled basis, by each investor-owned incumbent electric utility.  The reviews shall be conducted to determine, for a 12-month test period, whether the utility’s earnings have produced a fair combined rate of return on the utility’s common equity for its generation and distribution services. If a utility is earning less than a fair combined rate of return, its rates will be adjusted to provide such a return. If the utility is earning between 100 and 200 basis points above a fair combined rate of return on both its generation and distribution services in the test period, one-half of the excess is to be credited to customers; if it is earning between 200 and 300 basis points above, two-thirds is to be credited back; if earning between 300 and 400 basis points above, three-fourths is to be credited back; and if earning between more than 400 basis points above, all of such amount is to be credited back.  If a utility earned more than 100 basis points above a fair combined rate of return on both its generation and distribution services, and total aggregate regulated rates of such utility were more than five percent, compounded annually, above the total aggregate regulated rates of such utility determined in the biennial review for the base period, the SCC may direct that the earnings for such test period that were more than 100 basis points above the fair combined rate of return be credited to customers' bills.  A "fair rate of return" on common equity is 600 basis points above the latest available three month average bond yield of investment-grade bonds using Moody’s Long Term Baa Utility Bonds; however, if the bond yield exceeds 12 percent, the SCC may adopt an alternative method that produces a figure not less than 12 percent (which when added to the 600 basis point bump is 18 percent).  The Commission may increase or decrease the rate of return by up to 0.5 percentage points under a "Performance Incentive."  Costs for transmission services provided by PJM Interconnection and approved by the Federal Energy Regulatory Commission (FERC) and costs of FERC-approved demand response programs administered by PJM, are deemed reasonable and prudent and recoverable under a rate adjustment clause.  Utilities may also obtain, during or after the capped rate period, rate adjustment clauses, for various purposes, including demand-side management, conservation, renewable energy, energy efficiency and load management programs, which shall be approved if the costs or the need for the incentives are demonstrated with reasonable certainty.  The provision of the Virginia Electric Utility Restructuring Act that currently addresses the development of a coal-fueled generation facility in Southwest Virginia is amended to apply to other generation facilities, environmental projects, and major unit modifications of generation facilities and to provide that the utility has the right to recover the costs of the facility through its rates, including allowance for funds used during construction plus a fair rate of return, through a rate adjustment clause.  During such a rate proceeding, the SCC may examine the prudency of any cost incurred except for those transmission-related and FERC-approved demand response programs declared to be reasonable and prudent.  Costs that are recoverable through rate adjustment clauses will be considered on a stand-alone basis without regard to the other costs, revenues, investments or earnings, and the requests for their approval are to be decided within specified time limits.  After the capped rate period ends, only customers whose annual demand exceeds five megawatts will be permitted to purchase electricity from a competing provider of generation services.  The ability of large customers to purchase electric power from a licensed competitive supplier is subject to the condition that they cannot thereafter purchase electricity from their incumbent utility without giving five years’ notice, unless it demonstrates that the supplier failed to perform and that such customer is unable to obtain service from an alternative supplier.  If a customer receives an exemption from the five-year minimum stay requirement, the cost of its power during the exemption period will be the market-based costs of the utility.  The measure also (i) authorizes any public utility to apply to the Commission to implement rate design changes which overall, and by customer class, are not designed to increase or decrease the aggregate regulated operating revenues of such utility; (ii) directs that the fuel factor allowing the recovery of costs of purchased fuel by an electric utility that divested its generation assets prior to January 1, 2002, shall increase its regulated electric revenue by an amount not more than 20 percent of such revenue during the previous calendar year, with a deferral of any costs excluded by this limitation until subsequent proceedings, with interest at a rate no less than the rate for refunds in rate cases; (iii) provides that in fuel factor proceedings, energy revenues associated with off-system sales of power are to be credited against fuel factor expenses in an amount equal to the total incremental fuel factor costs incurred in the production and delivery of such sales, with 50 percent of the total positive accumulated energy revenues received from off-system sales transactions, less the total incremental costs incurred in the production and delivery of such sales, being credited against fuel factor expenses and 50 percent of the energy margins not being considered in the new biennial reviews of electric utilities' rates; (iv) repeals the existing provision that allows the Commission to dispense with the fuel factor procedures for any electric utility if it finds that its fuel costs can be reasonably recovered through rates established through other provisions; and (v) requires utilities to file plans for how they will meet generation and transmission requirements to serve native load for the ensuing 10 years.  Provisions of the Restructuring Act that exempt the generation of electric energy from regulation, prohibit public service corporations from exercising the power of eminent domain to acquire property for generation facilities, authorize the Commission to take certain actions to expand transmission capacity, and authorize competition for metering and billing services are repealed.