driven primarily by weather, customer growth and usage per customer. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As part of this continued focus, we have implemented an asset management process to ensure that we are optimizing our investments to balance cost, performance and risk. We are also using technology to enhance customer service options. As we move toward the future, safety, operational performance and customer relationships will remain as key focal areas.

Revenue provided by our electric transmission operations is based primarily on rates approved by the Federal Energy Regulatory Commission (FERC). The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability results from changes in rates, the demand for services, which is primarily weather dependent, and operating and maintenance expenditures. We are a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO) and our electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to the North American Electric Reliability Corporation (NERC) by the Energy Policy Act of 2005 (EPACT), we are committed to meeting NERC standards, modernizing our infrastructure and maintaining superior system reliability. We will continue to focus on safety, operational performance and execution of PJM’s Regional Transmission Expansion Plan (RTEP) as we move toward the future.

CompetitionCOMPETITION

Within Delivery’sDVP’s service territory in Virginia and North Carolina, there is no competition for electric distribution service.

Additionally, since our electric transmission facilities are integrated into PJM, our electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. In our transmission and distribution operations, we are seeing continued strong growth in new customers and increased usage per customer on a weather-normalized basis. Growth is particularly strong in the major metropolitan areas of Virginia. The combination of higher energy usage and efficient operations and maintenance spending has been critical to our performance. Operationally, we continue to enhance the customer experience through solid reliability performance and by completing the automation of all of our electric residential meters.

RegulationREGULATION

Delivery’sDVP’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia StateCorporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission). SeeRegulation—Regulation—State Regulations for additional information. DVP’s electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. SeeState Regulations andFederal Regulations inRegulation for additional information.

Generation’s earnings primarily result from the generation and sale of electricity. Due to 1999 Virginia deregulation legislation, as amended in 2004 and 2007, revenues for serving Virginia jurisdictional retail load are based on capped rates through 2008. Additionally, fuel costs, including purchased power, were subject to fixed-rate recovery provisions until July 1, 2007. Pursuant to the 2007 amendments to the fuel cost recovery statute, annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, were instituted beginning July 1, 2007 for our Virginia jurisdictional customers. As discussed inStatus of Electric Regulation in Virginia underRegulation, the Virginia General Assembly enacted legislation in April 2007 that returned the Virginia jurisdiction of our generation operations to a modified cost-of-service rate model, subject to rate caps in effect through December 31, 2008. During the remainder of the capped rate period, changes in our operating costs relative to costs used to establish capped rates, will likely impact our earnings.

Variability in earnings also results from changes in demand, which is primarily dependent on the weather, the cost of labor and benefits and the timing, duration and costs of outages.

CompetitionCOMPETITION

For our electric generation operations, retailRetail choice has been available forto our Virginia jurisdictional electric customers since January 1, 2003; however, to date, competition in Virginia has not developed to any significant extent. In April 2007, the extent originally anticipated.Virginia General Assembly passed legislation ending retail choice for most of our Virginia jurisdictional electric utility customers, effective January 1, 2009. SeeRegulation—State Regulations. Currently, North Carolina does not offer retail choice to electric customers.

RegulationREGULATION

In Virginia and North Carolina,The operations of our electric utility generation facilities, along with power purchases, are used to serve our utility service area obligations. Due to amendments to the Virginia Restructuring Act and the fuel factor statute in 2004, revenues for serving Virginia jurisdictional retail load are based on capped base rates through 2010 and the related fuel costs for the generating fleet, including power purchases,Generation segment are subject to fixed rate recovery provisions until July 1, 2007, when a one-time adjustment will be made effective through December 31, 2010. Such adjustment will be prospectiveregulation by the Virginia Commission, North Carolina Commission, FERC, Nuclear Regulatory Commission (NRC), Environmental Protection Agency (EPA), Department of Energy (DOE), Army Corps of Engineers and will not take into account any over-recovery or under-recovery of prior fuel costs. Subject to market conditions, any generation remaining after meeting utility system needs is sold into PJM. SeeRegulation for additional information.

other federal, state and local authorities.

PropertiesPROPERTIES

For a listing of our current generation facilities, see Item 2. Properties.

Based on available generation capacity and current estimates of growth in customer demand in our utility service area, we will need additional generation capacity over the next ten years. We have announced a comprehensive generation growth program, referred to asPowering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in our core market in Virginia. As part of this program, the following projects are in various stages of development:

In April 2007, we filed an application with the Virginia Commission requesting approval to add two 150 megawatt (Mw) natural gas-fired electric generating units (Units 3 and 4) to our Ladysmith power station (Ladysmith) to supply electricity during periods of peak demand. The Virginia Commission approved the application in August 2007, and construction has commenced. In December 2007, we received approval from the North Carolina

regulatory approval, we plan to build a combined cycle unit with operations expected to begin in summer 2011.

Sources of Fuel SupplySOURCESOF ENERGY SUPPLY

Generation uses a variety of fuels to power itsour electric generation including procuring purchased power for system load requirements, as described below. Generation provides electricity primarily from nuclear, coal, oil, purchased power and natural gas. Presented below is a summary of the system’s output by energy source:

Nuclear Fuel—Fuel—Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Some of these agreements have fixed commitments and are included as contractual obligations inFuture Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A). Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices.prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs.needs for the near term. Additional fuel is purchased as required to ensure optimal cost and inventory levels.

Fossil Fuel—Fuel—Generation primarily utilizes coal, oil and natural gas in its fossil fuel plants. Generation’s coal supply is obtainedthroughobtained through long-term contracts and spot purchases. Additional utility requirements are purchased mainly under short-term spot agreements.

We haveGeneration’s natural gas and oil supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from underground storage fields owned by Dominion or third parties. Generation manages a portfolio of firm natural gas transportation contracts (capacity) that allow flexibleallows flexibility in delivering natural gas deliveries to our gas turbine fleet, while minimizing costs.

Purchased Power—Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for system load requirements.

SeasonalitySEASONALITY

Sales of electricity for the Generation segment typically vary seasonally basedas a result of the impact of changes in temperature on demand for electricity by residential and commercial customers forto meet cooling and heating use due to seasonal changes in temperature.needs.

The pilots will be offered to a selection of 4,550 customers in our central, eastern and northern Virginia service areas. To help ensure that the results are representative, customers will not be able to volunteer for the pilots nor participate in more than one pilot. We will report results from the pilots at least quarterly to the Virginia Commission staff to help evaluate their effectiveness.

The pilots approved by the Virginia Commission include:

Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have passed legislation setting goals for renewable power. We are committed to meeting Virginia’s goal of 12% renewable power by 2022 and North Carolina’s renewable portfolio standard of 12.5% by 2021.

We are actively assessing development opportunities in our service territories for renewable technologies. In November, 2007 we issued a request for proposals (RFP) for renewable energy projects in Virginia, North Carolina or elsewhere in the Corporate segment arePJM Interconnect region. The RFP seeks the discontinued operationspurchase of renewable energy generation projects, as well as renewable energy credits. Generation currently provides approximately two percent of its generation from renewable sources. We also anticipate using up to 20% biomass (woodwaste) at the proposed Virginia PowerCity Hybrid Energy Marketing, Inc. (VPEM), previously a subsidiary, that was transferred to DominionCenter discussed in December 2005. SeeRecent DevelopmentsGeneration-Properties and Notes 1, 8 and 25 to our Consolidated Financial Statements..

We have announced a comprehensive generation growth program, referred to asPoweringVirginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in our core market of Virginia. The new generation planned in connection with this program is discussed further underGeneration-Properties. We expect that these investments collectively will provide the following benefits: expanded electricity production capability; increased technological and fuel diversity; and a reduction in the carbon dioxide (CO₂) emissions intensity of our generation fleet. A critical aspect of thePoweringVirginia program is the extent to which we seek to reduce the carbon intensity of our generation fleet by developing generation facilities with zero CO₂ and low CO₂ emissions, as well as economically viable facilities that can be equipped for CO₂ separation and sequestration. There is no current technological solution

new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the United States Court of Appeals for the Seventh Circuit. We cannot predict the outcome of the appeal.

We are also subject to FERC’s Standards of Conduct that govern conduct between interstate transmission gas and electricity transmission providers and their marketing function or their energy relatedenergy-related affiliates. The rule defines the scope of the affiliates covered by the standards and is designed to prevent transmission providers from giving their marketing functions or affiliates undue preferences.

EPACT included provisions to create an Electric Reliability Organization (ERO). The ERO is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. In 2006, FERC certified NERC as the ERO beginning on January 1, 2007. In late 2006, FERC also issued an initial order approving many reliability standards, that went into effect on January 1, 2007. Beginning on June 4, 2007, entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed with non-monetary penalties, depending upon the nature and severity of the violation.

We have planned and operated our facilities in compliance with earlier NERC voluntary standards for many years and are fully aware of the new requirements. We participate on various NERC committees, track development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. While we expect that there will be some additional cost involved in maintaining compliance as standards evolve, we do not expect the expenditures to be significant.

Environmental Regulations

Each of our operating segments faces substantial regulationlaws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. If our expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates, those costs could adversely affect future results of operations and cash flows. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Company. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, seeEnvironmental Matters inFuture Issues and Other Matters in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 21 to our Consolidated Financial Statements.

From timeThe Clean Air Act (CAA) is a comprehensive program utilizing a broad range of regulatory tools to time, weprotect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may be identified as a potentially responsible partychoose to a Superfund site. The EPA (or a state) can either (a) allow such a partydevelop regulatory programs that

Nuclear Regulatory Commission

All aspects of the operation and maintenance of our nuclear power stations, which are part of theour Generation segment, areregulatedare regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, itthat action could result in substantial increases in the cost of operating and maintaining our nuclear generating units.

The NRC also requires us to decontaminate our nuclear facilities once operations cease. This process is referred to as decommissioning, and we are required by the NRC to be financially prepared. For information on ourthe decommissioning trusts that have been established for this purpose, seeGeneration—NuclearDecommissioning and Note 9 to our Consolidated Financial Statements.

Item 1A. Risk Factors

Our business is influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond our control. We have identified a number of these factors below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, seeForward-Looking Statements in MD&A.

Our operations are weather sensitive. Our results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, and droughts, can be destructive, causing outages and property damage that require us to incur additional expenses. In addition, droughts can result in reduced water-levels that could adversely affect operations at some of our power stations.

We are subject to complex governmental regulation that could adversely affect our operations. Our operations are subject to extensive federal, state and local regulation and may require numerous permits, approvals and certificates from various governmental agencies. We must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for our existing operations and that our business is conducted in accordance with applicable laws. However, new laws or regulations, or the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may require us to incur additional expenses.

We could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of bulk power transmission systems, including the Company, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. If we are found not to be in compliance with the mandatory reliability standards we could be subject to sanctions, including substantial monetary penalties.

cannot estimate the effect of any such legislation on our results of operations, financial condition, or our customers.

We are exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia. Under the Virginia Restructuring Act, as amended in 2004 and 2007, our base rates (excluding, generally, a fuel factor with limited adjustment provisions, and certain other allowable adjustments) remain capped through December 31, 2010 unless modified or terminated consistent with the Virginia Restructuring Act.2008. Although the Virginia Restructuring Act allows for the recovery of certain generation-related costs during the capped rates period, we remain exposed to numerous risks of cost-recovery shortfalls. These include exposure to stranded costs, future environmental compliance requirements, certain tax law changes,shortfalls, such as costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs.unanticipated events.

In addition, under the 2004 amendments to the Virginia fuel factor statute, our current Virginia fuel factor provisions are locked-in until the earlier of July 1, 2007 or the termination of capped rates by order of the Virginia Commission, with no deferred fuel accounting. The amendments provide for a

one-time adjustment of our fuel factor, effective July 1, 2007through December 31, 2010 (unless cappedOur base rates are terminated earlier), with no adjustment for previously incurred over-recovery or under-recovery.subject to regulatory review. As a result of the current locked-in fuel factor and the uncertainty of what the one-time adjustmentRestructuring Act, commencing in 2009, our base rates will be we are exposed to fuel pricereviewed by the Virginia Commission under a modified cost-of-service model. Such rates will be set based on analyses of our costs and other risks. These risks include exposure to increased costs of fuel, including purchased power costs, differences between our projectedcapital structures, as reviewed and actual power generation mix and generating unit performance (which affects the types and amounts of fuel we use) and differences between fuel price assumptions and actual fuel prices.

approved in regulatory proceedings. Under the Virginia Restructuring Act, the generation portion of our electric utility operations is openVirginia Commission may, in a proceeding conducted in 2009, reduce rates or order a credit to competition and resulting uncertainty. Undercustomers if we are deemed to have earnings during a 2008 test period which are more than 50 basis points above a return on equity level to be established by the Virginia Restructuring Act,Commission in that proceeding. After the generation portioninitial rate case, the Virginia Commission will review our rates biennially and may order a credit to customers if we are deemed to have earned more than 50 basis points above a return on equity level established by the Virginia Commission and may reduce rates if we are found to have had earnings in excess of the established return on equity level during two consecutive biennial review periods.

Energy conservation could negatively impact our electric utility operations in Virginia is openfinancial results. A number of regulatory and legislative bodies have introduced requirements and/or incentives to competition and is no longer subject to cost-based regulation.reduce energy consumption by certain dates. To date, a competitive retail market has been slow to develop. Consequently, it is difficult to predict the pace at which a competitive environment will evolve and the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, it could negatively impact us depending on the regulatory treatment of the associated impacts. Should we be required to which weinvest in conservation measures that resulted in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We are unable to determine what impact, if any, conservation will face increased competition and be able to operate profitably within this competitive environment.have on our financial condition or results of operations.

There are risks associated with the operation of nuclear facilities.We operate nuclear facilities that are subject to risks, including the threat of terrorist attack and our ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and our ability to maintain adequate reserves for decommissioning, costs of replacement power, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. We maintain decommissioning trusts and external insurance coverage to managemitigate the financial exposure to these risks. However, it is possible that decommissioning costs could exceed the amounts in our trusts or that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses and liquidity constraints.We use derivative instruments, including futures, swaps, forwards, options and financial transmission rights options and swaps, to manage ourthe commodity and financial market risks.risks of our business operations. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a

company or changes to our credit ratings. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled.

Changing rating agency requirements could negatively affect our growth and business strategy.strategy. As of February 1, 2006,2008, our senior unsecured debt is rated BBB,A-, stable outlook, by Standard & Poor’s Rating GroupRatings Services, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s); A3, under review for possible downgrade,Baa1, stable outlook, by Moody’s Investors Service (Moody’s); and BBB+, stable outlook, by Fitch Ratings Ltd. (Fitch). In order to maintain our current credit ratings in light of existing or future requirements, we may find it necessary to take steps or change our business plans in ways that may adversely affect our growth and earnings. A reduction in our credit ratings by Standard & Poor’s, Moody’s or Fitch could increase our borrowing costs and adversely affect operating results.

Potential changes in accounting practices may adversely affect our financial results. We cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or our operations specifically. New accounting standards could be issued that could change the way we record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect our reported earnings or could increase reported liabilities.

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on our operations. Implementation of our growth Our business strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future financial condition.operating results.

Item 1B. Unresolved Staff Comments

None.

SeeDVP, Generation andRegulation in Item 1. Business,Future Issues and Other Matters in MD&A and Note 21 to our Consolidated Financial Statements for additional information on various environmental, rate matters and variousother regulatory proceedings to which we are a party.

Item 4. Submission of Matters to a Vote of Security Holders

None.

Additionally, other risks that could cause actual results to differ from predicted results are set forth in Item 1A. Risk Factors.

Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results.

We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

IntroductionINTRODUCTION

Virginia Electric and Power Company, a Virginia public service company, is a wholly-owned subsidiary of Dominion. We are a regulated public utility that generates, transmits and distributes electricity within an area of approximately 30,000 square milesfor sale in Virginia and northeastern North Carolina. We serve approximately 2.32.4 million retail customer accounts, including governmental agencies, andas well as wholesale customers such as rural electric cooperatives municipalities, power marketers and other utilities. The Virginia service area comprises about 65% of Virginia’s total land area, but accounts for over 80% of its population.municipalities.

On December 31, 2005,Prior to a fourth quarter segment realignment, we completed the transfer ofmanaged our indirect wholly-owned subsidiary, Virginia Power Energy Marketing, Inc. (VPEM), to Dominion through a series of dividend distributions in exchange for a capital contribution. VPEM provides fuel and risk management services to us by acting as an agent for one of our other indirect wholly-owned subsidiaries and will continue to provide these services following the transfer. VPEM also engages in energy trading activities and provides price risk management services to other Dominion affiliates through the use of derivative contracts. While we owned VPEM, certain of these derivative contracts were required to be reported at fair value on our Consolidated Balance Sheets, with changes in fair value reflected in earnings. These price risk management activities for Dominion affiliates generated derivative gains and losses that in turn affected our Consolidated Financial Statements.

As a result of the transfer, VPEM’s results ofdaily operations will no longer be included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation.

11

Our businesses are managed through three primary operating segments: Delivery, Energy and Generation. During the fourth quarter of 2007, we realigned our business units and began managing our daily operations through two primary operating segments: Dominion Virginia Power (DVP) and Generation. We also report a Corporate and Other segment that includes our corporate and other functions. While we manage our daily operations through our operating segments, our assets remain wholly-owned by us and our legal subsidiaries.

The contributions to net income by our primary operating segments are determined based on a measure of profit that we believe represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by management in assessing segment performance or allocating resources among the segments. Those specific items are reported in the Corporate and Other segment.

DeliveryDVP includes our regulated electric transmission and distribution operations in Virginia and northeastern North Carolina,

beginning July 1, 2007 for our Virginia jurisdictional customers. As discussed inStatus of Electric Regulation in VirginiaunderFuture Issues and Other Matters, the Virginia General Assembly enacted legislation in April 2007 that returned the Virginia jurisdiction of our generation operations to a one-time prospective adjustment will be made effectivemodified cost-of-service rate model, subject to rate caps in effect through December 2010.

Changes31, 2008. During the remainder of the capped rate period, changes in our utility operating costs particularly with respect to fuel and purchased power, relative to costs used to establish thecapped rates, will likely impact our earnings. Variability in earnings also results from changes in demand, which is primarily dependent on the weather, dependent, the cost of labor and benefits and the timing, duration and costs of outages.

Corporate and Otherincludes our corporate and other functions, the net impact of VPEM and specific items attributable to our primary operating segments that are excluded from thenot included in profit measures evaluated by executive management, in assessing segmentthe segments’ performance or allocating resources among the segments.segments, including the net impact of Virginia Power Energy Marketing, Inc. (VPEM) prior to its transfer to Dominion.

On December 31, 2005, we completed the transfer of our indirect wholly-owned subsidiary, VPEM, to Dominion through a series of dividend distributions in exchange for a capital contribution. VPEM provides fuel and risk management services to us by acting as an agent for one of our other indirect wholly-owned subsidiaries. VPEM also engages in energy trading activities and provides price risk management services to other Dominion affiliates through the use of derivative contracts. While we owned VPEM, certain of these derivative contracts were required to be reported at fair value in our Consolidated Balance Sheets, with changes in fair value reflected in earnings. These price risk management activities for Dominion affiliates generated derivative gains and losses that in turn affected our Consolidated Financial Statements.

As a result of the transfer, VPEM’s results of operations are no longer included in our Consolidated Financial Statements, and our Consolidated Statements of Income for periods prior to the transfer have been adjusted to reflect VPEM as a discontinued operation.

Accounting MattersACCOUNTING MATTERS

Critical Accounting Policies and Estimates

We have identified the following accounting policies, including certain inherent estimates, that as a result of the judgments, uncertainties, uniqueness and complexities of the underlying accounting standards and operations involved, could result in material changes to our financial condition or results of operations under different conditions or using different assumptions. We have discussed the development, selection and disclosure of each of these policies with our Board of Directors, thatwhich also serves as our Audit Committee.

Accounting for derivative contracts at fair value

We use derivative contracts, such as futures, swaps, forwards, options and financial transmission rights (FTRs), to buy and sell energy-related commodities and to manage our commodity and financial markets risks. Derivative contracts, with certain exceptions, are subject to fair value accounting and are reported on our Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies.

Fair value of derivatives is based on actively quoted market prices, if available. In the absence of actively quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, we must estimate prices based on available historical and near-term future price information and use of statistical methods. For options and contracts with option-like characteristics where pricing information is not available from external sources, we generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions. We use other option models under special circumstances, including a Spread Approximation Model, when contracts include different commodities or commodity locations and a Swing Option Model, when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, we estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. If pricing information is not available from external sources, judgment is required to develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

For cash flow hedges of forecasted transactions, we must estimate the future cash flows of the forecasted transactions, as well as evaluate the probability of occurrence and timing of such transactions. Changes in conditions or the occurrence of unforeseen events could require discontinuance of hedge accounting or could affect the timing of the reclassification of gains and/or losses on cash flow hedges from accumulated other comprehensive income (loss) (AOCI) into earnings.

Use of estimates in long-lived asset impairment testing

Impairment testing for an individual or group of long-lived assets or intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves our judgment in areas such as identifying

12

circumstances indicating an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including the selection of an appropriate discount rate. Although our cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed. In 2005 and 2004, we did not test any significant long-lived assets or asset groups for impairment as no circumstances arose that indicated an impairment may exist.

Asset retirement obligations

We recognize liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These asset retirement obligations (AROs) are recognized at fair value as incurred, and are capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, we estimate the fair value of our AROs using present value techniques, in which we make various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. AROs currently reported on our Consolidated Balance Sheets were measured during a period of historically low interest rates. The impact on measurements of new AROs, using different rates in the future, may be significant. In the future, if we revise any assumptions used to calculate the fair value of existing AROs, we will adjust the carrying amount of both the ARO liability and related long-lived asset. We record accretion expense, increasing the ARO liability, with the passage of time. In 2005, 2004 and 2003, we recognized $44 million, $42 million and $38 million, respectively, of accretion expense, and expect to incur $47 million in 2006.

A significant portion of our AROs relate to the future decommissioning of our nuclear facilities. At December 31, 2005, nuclear decommissioning AROs, which are reported in the Generation segment, totaled $798 million, representing approximately 96% of our total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with our nuclear decommissioning obligations.

We obtain from third-party experts periodic site-specific “base year” cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for our nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these cost estimates are dependent on subjective factors, including the selection of cost escalation rates, which we consider to be a critical assumption.

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of our nuclear facilities. The use of alternative rates would have been material to the liabilities recognized. For example, had we increased the cost escalation rate by 0.5%, the amount recognized as of December 31, 2005 for our AROs related to nuclear decommissioning would have been $156 million higher.

Accounting for regulated operationsCCOUNTINGFOR REGULATED OPERATIONS

The accounting for our regulated electric operations differs from the accounting for nonregulated operations in that we are required to reflect the effect of rate regulation in our Consolidated Financial Statements. Specifically, ourFor regulated businesses record assets and liabilitiessubject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting

rates. AROs currently reported in our Consolidated Balance Sheets were measured during a period of historically low interest rates. The impact on measurements of new AROs, or remeasurements of existing AROs, using different rates in the future, may be significant. When we revise any assumptions used to calculate the fair value of existing AROs, we adjust the carrying amount of both the ARO liability and the related long-lived asset. We accrete the ARO liability to reflect the passage of time. In 2007, 2006 and 2005, we recognized $38 million, $40 million and $44 million, respectively, of accretion and expect to incur $38 million in 2008. Upon reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations, we began recording accretion and depreciation associated with nuclear decommissioning AROs, formerly charged to expense, as an adjustment to the regulatory liability for nuclear decommissioning trust funds previously discussed, in order to match the recognition for rate-making purposes.

A significant portion of our AROs relates to the future decommissioning of our nuclear facilities. At December 31, 2007, nuclear decommissioning AROs, which are reported in the Generation segment, totaled $637 million, representing approximately 94% of our total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with our nuclear decommissioning obligations.

We utilize periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for our nuclear plants. We obtained updated cost studies for both of our nuclear plants in 2006 which reflected increases in base year costs. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, our cost estimates include cost escalation rates that are applied to the base year costs. The selection of these cost escalation rates is dependent on subjective factors which we consider to be a critical assumption.

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of our nuclear facilities. The use of alternative rates could have been material to the liabilities recognized. For example, had we increased the cost escalation rate by 0.5%, the amount recognized as of December 31, 2007, for our AROs, related to nuclear decommissioning would have been $117 million higher.

Income taxesREVENUE RECOGNITION—UNBILLED REVENUE

We recognize and record revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters which is performed on a systematic basis throughout the month. At the end of each month, the amounts of electric energy delivered to customers, but not yet billed, is estimated and recorded as unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Our customer receivables included $270 million and $233 million of accrued unbilled revenue at December 31, 2007 and 2006, respectively.

The calculation of unbilled revenues is complex and includes numerous estimates and assumptions including historical usage,

that all, or a portion of, a deferred tax asset will not be realized. At December 31, 2007, we had no valuation allowances on our deferred tax assets.

ACCOUNTING STANDARDS

13

Newly Adopted Accounting Standards

During 2005, 20042007, 2006 and 2003,2005, we were required to adopt several new accounting standards, the requirements of which are discussed in Note 3 to our Consolidated Financial Statements. The adoptionSee Note 4 to our Consolidated Financial Statements for a discussion of Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003),Consolidation of Variable Interest Entities, (FIN 46R) on December 31, 2003 with respect to special purpose entities, affectedrecently issued accounting standards that will be adopted in the comparability of our 2005 and 2004 Consolidated Statements of Income to 2003 as follows:future.

Results of OperationsRESULTSOF OPERATIONS

Presented below is a summary of contributions by our operating segments to net income:consolidated results:

Overview

2005 vs. 2004

The combined net income contribution of our primary operating segments decreased 28% to $539 million, as compared to 2004, primarily reflecting a lower contribution from the Generation segment. The lower contribution was largely due to higher fuel and purchased power expenses, primarily resulting from higher commodity prices.

The decrease in net income was also impacted by the following items recognized in 2005 and reported in the Corporate segment:

In addition, the decrease in net income was impacted by items recognized in 2004 and reported in the Corporate segment that are discussed in further detail below.

2004 vs. 20032007VS. 2006

Net income decreased 2%by 6% to $744 million, as compared$448 million. Unfavorable drivers include an extraordinary charge in connection with the reapplication of SFAS No. 71 to 2003, largely reflectingthe Virginia jurisdiction of our generation operations, an increase in outage costs primarily due to an increase in the number of scheduled outage days at certain of our electric generating facilities and a lower contributiondecrease in gains from the Generation segment, primarilysales of emissions allowances. Favorable drivers include an increase in regulated electric sales resulting from favorable weather, customer growth and other factors, and lower fuel expense due to the eliminationreinstatement of annual fuel deferral accounting for the Virginia jurisdiction. The elimination of fuel deferral accountingrate adjustments, effective July 1, 2007, for the Virginia jurisdiction resulted in the recognitionof our generation operations, with deferred fuel accounting for over- or under-recoveries of fuel expensescosts.

2006VS. 2005

Net income increased to $478 million. Favorable drivers include the absence of $471 million of after-tax losses incurred in 2005 by the discontinued operations of VPEM and the absence of a 2005 charge resulting from the termination of a long-term power purchase agreement. Our results were also positively impacted by decreased consumption of fossil fuel due to milder weather and an increase in gains realized from the sale of emissions allowances. Unfavorable drivers include a decrease in regulated electric sales resulting from milder weather and other factors; a reduced benefit from financial transmission rights (FTRs) in excess of amounts recoveredcongestion costs and major storm damage and service restoration costs associated with tropical storm Ernesto in fixed fuel rates.September 2006.

deferral accounting, increased by approximately $501 million due to higher consumption of fossil fuel and purchased power resulting from an increase in the number of heating and cooling degree days, higher commodity costs and a change in generation mix. This increase was largely offset by a $408 million decrease primarily due to the deferral of fuel expenses that were in excess of current period fuel rate recovery.

Purchased electric capacity expensedecreased 5% to $429 million, primarily due to scheduled capacity reductions for certain long-term power purchase contracts.

Other energy-related commodity purchases expensedecreased 52% to $27 million, primarily reflecting a decrease in nonutility coal activities that have been substantially exited.

Other operations and maintenance expenseincreased 25% to $1.3 billion, primarily reflecting:

Depreciation and amortization expenseincreased 6% to $568 million, due to incremental expense resulting from property additions, a change in depreciation rates for our generation assets to reflect the results of a new depreciation study and increased amortization expense associated with emissions allowances held for consumption.

Other taxesincreased 6% to $173 million, primarily due to the recognition of increased property taxes in 2007, reflecting changes in tax rates and assessed valuations.

Other income decreased 27% to $55 million, resulting primarily from the recognition of decommissioning trust earnings as a regulatory liability due to the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

Extraordinary itemreflects a $158 million after-tax charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our generation operations.

These benefits were partially offset by the following charges in 2005:

Depreciation and amortization expense increased 6% to $527 million, due to incremental expense resulting from property additions.

Other income increased 43% to $70 million primarily reflecting a $9 million increase in net realized gains (including investment income) associated with nuclear decommissioning trust fund investments, a $3 million increase in rental income and a $2 million increase in interest income.

Interest and related charges increased 29% to $322 million, primarily reflecting the impact of prepayment penalties resulting from the early redemption of debt, additional borrowings and higher interest rates on variable rate debt.

Loss from discontinued operations increased as a result of unfavorable price changes on unsettled commodity derivative contracts primarily used to execute price risk management activities undertaken on behalf of our affiliates.

2004 vs. 2003

Operating Revenue increased 3% to $5.4 billion, primarily reflecting:

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 19% to $1.8 billion, primarily reflecting:

15

Purchased electric capacity expense decreased 9% to $550 million, driven by the termination of certain long-term power purchase agreements as a result of the purchase of the related nonutility generating facilities.

Other energy-related commodity purchases expense decreased 69% to $38 million, primarily reflecting a decrease in the cost of coal purchased for resale.

Depreciation and amortization expense increased 8% to $496 million, due to incremental expense resulting from property additions, including the consolidation of a variable interest lessor entity as a result of adopting FIN 46R at December 31, 2003.

Other income decreased 38% to $49 million, primarily reflecting lower net realized gains (including investment income) associated with nuclear decommissioning trust fund investments ($12 million), decreased interest income ($8 million) and decreased net gains on the disposition of assets ($5 million).

Interest and related charges decreased 17% to $249 million, primarily due to refinancing of callable mortgage bonds with lower cost unsecured debt in December 2003.

Loss from discontinued operations increased as a result of unfavorable price changes on unsettled commodity derivative contracts primarily used to execute price risk management activities undertaken on behalf of our affiliates.

Outlook

We believe our operating businesses will provide stable growth in net income in 2006. The following are growth factors that will impact these expected results:

The growth factors in 2006 will be partially offset by:

Based on these projections, we estimate that cash flow from operations will increase in 2006, as compared to 2005. Management believes this increase will provide sufficient cash flow to maintain or grow our current dividend to Dominion.

Segment Results of Operations

Delivery

Delivery includes our electric distribution system and customer service operations.

mwhrs = megawatt hours

Presented below, on an after-tax basis, are the key factors impacting the Delivery segment’s operating results:

2005 vs. 2004

Interest and related chargesdecreased 8% to $296 million, primarily reflecting the absence of prepayment penalties resulting from the early redemption of debt in 2005, partially offset by additional borrowings and higher interest rates on variable rate debt.

Loss from discontinued operationsreflects the absence of losses incurred by the discontinued operations of VPEM prior to its disposition in December 2005.

Outlook

We believe our operating businesses will provide stable growth in net income in 2008. The following are growth factors that will impact these expected results:

The growth factors in 2008 are expected to be partially offset by:

2004 vs. 2003SEGMENT RESULTSOF OPERATIONS

Presented below is a summary of contributions by our operating segments to net income: