service level lines in Virginia and North Carolina. The right-of-wayrights-of-way grants for most of our electric lines have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

Sources of Fuel SupplySOURCES OF ENERGY SUPPLY

Delivery’s supply of electricity to serve our retail customers is primarily providedproduced or procured by the Generation segment. SeeGeneration for additional information.

SeasonalitySEASONALITY

Delivery’s business varies seasonally basedas a result of the impact of changes in temperature on demand for electricity by residential and commercial customers for electricity to meet cooling and heating use due to changes in temperature.

needs.

Energy

Energy includes our tariff-basedregulated electric transmission system serving Virginia and northeastern North Carolina. On May 1,In 2005, we became a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO). As a result, we, and integrated our control areaelectric transmission facilities into the PJM energywholesale electricity markets.

CompetitionCOMPETITION

Since the integration of our electric transmission facilities into PJM, our electric transmission business isservices are administered by PJM and are no longer subject to competition in relation to transmission service provided to customers within the PJM region.

RegulationREGULATION

Energy’s electric transmission operationsrates, tariffs and terms of service are subject to regulation by the Federal Energy Regulatory Commission (FERC),. Electric transmission siting authority remains the exclusive jurisdiction of the Virginia Commission and the North Carolina Commission.Commissions. However, the Energy Policy Act of 2005 (EPACT) provides FERC with certain limited backstop authority for transmission siting, the implications of which remain unclear. SeeRegulation—Regulation—State Regulations andRegulation—Regulation—Federal Regulations for additional information.

PropertiesPROPERTIES

The Energy segment has approximately 6,000 miles of electric transmission lines of 69 kilovolt (kV) or more located in the states of North Carolina, Virginia and West Virginia. Portions of the electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in the line, if any exists. these lines.

While we continue to own and maintain these electric transmission facilities, they are now a part of PJM, which coordinates the planning, operation, emergency assistance, and exchanges of capacity and energy for such facilities.

Each year, as part of PJM’s Regional Transmission Expansion Plan (RTEP) process, reliability projects are authorized. In June 2006, PJM, through the RTEP process, authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects. The first project is an approximately 270-mile 500-kV transmission line from southwestern Pennsylvania to Virginia, of which we will construct approximately 70 miles in Virginia and a subsidiary of Allegheny Energy, Inc. will construct the remainder. The second project is

supply needs. 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.

SeasonalitySEASONALITY

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

Nuclear DecommissioningNUCLEAR DECOMMISSIONING

Generation has four licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia that serve our customers. Decommissioning representsinvolves the decontamination and removal of radioactive contaminants from a nuclear power plant once operations have ceased, in accordance with standards established by the Nuclear Regulatory Commission (NRC).NRC. Amounts collected from ratepayers and placed into trusts have been invested to fund the expected future costs of decommissioning the Surry and North Anna units.

The total estimated cost to decommission our four nuclear units is $1.5$1.8 billion in 2006 dollars and is primarily based upon site-specific studies completed in 2002. We will perform new cost studies in 2006. The current cost estimate assumes that the method of completingestimates assume decommissioning activities is prompt dismantlement. During 2003,will begin shortly after cessation of operations, which will occur when the NRC approved our application for a 20-year life extension foroperating licenses expire. We expect to decommission the Surry and North Anna units.

We expect to decommission the units during the period 2032 to 2045.2059.

Corporate

We also have a Corporate segment. Corporate includes our corporate and other functions and specific items attributable to our operating segments that arehave been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments. Also included in the Corporate segment are the discontinued operations of Virginia Power Energy Marketing, Inc. (VPEM), previously a subsidiary, that was transferred to Dominion in December 2005. SeeRecent Developments and Notes 1, 8 and 25 to our Consolidated Financial Statements.

Fuel prices have increased considerably since our Virginia fuel factor provisions were frozen in 2004, which has resulted in our fuel expenses being significantly in excess of our rate recovery. We expect that fuel expenses will continue to exceed rate recovery until our fuel factor is adjusted in July 2007.

When While the 2006 amendments do not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor is adjusted, in July 2007, we will remain subject to the risk thatof under-recovery of prudently incurred fuel factor-related cost recovery shortfalls may adversely affect our margins. Conversely, we could experience a positive economic impact to the extent that we can reduce our fuel factor-related costs for our electric utility generation operations.

Other amendments to the Virginia Restructuring Act were also enacted in 2004 with respect to a minimum stay exemption program, a wires charge exemption program and the development of a coal-fired generating plant in southwest Virginia for serving default service needs. Under the minimum stay exemption program, large customers with a load of 500 kilowatts or greater would be exempt from the twelve-month minimum stay obligation under capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply service with a competitive service provider. The wires charge exemption program would allow large industrial and commercial customers, as well as aggregated customers in all rate classes, to avoid paying wires charges when selecting electricity supply service from a competitive service provider by agreeing to market-based pricing upon return to the incumbent utility. For 2006, our wires charges are set at zero for all rate classes. In February 2005, we joined a consortium to explore the development of a coal-fired electric power station in southwest Virginia.

SeeStatus of Electric Deregulation in Virginiaand Recovery of Stranded Costs inFuture Issues and Other Matters in MD&A for additional information on capped base rates and stranded costs.

Retail Access Pilot Programs

The three retail access pilot programs, approved by the Virginia Commission in 2003, continue to be available to customers. There are currently six competitive suppliers and seven aggregators registered with us and licensed to supply electricity to customers in Virginia. Currently, the relationship between capped rates and market prices makes customer switching difficult.

Rate Matters

Virginia—In December 2003, the Virginia Commission approved the proposed settlement of our 2004 fuel factor increase of $386 million. The settlement included a recovery period for the under-recovery balance over three and a half years. Approximately $171 million and $85 million of the $386 million was recovered in 2004 and 2005, respectively. The remaining unrecovered balance is expected to be recovered by July 1, 2007.

As a result of amendments to the Virginia Restructuring Act in 2004, our capped base rates were extended to December 31, 2010. In addition, our fuel factor provisions were frozen until July 1, 2007, when they will be adjusted once for the period through December 31, 2010. SeeStatus of Electric Deregulation in Virginia above for additional information regarding the Virginia Restructuring Act amendments.

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2010 is greatly diminished.

North Carolina—In connection with the North Carolina Commission’s approval of Dominion’s acquisition of Consolidated Natural Gas Company (CNG), in 2000, we agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on our operations. However, in 2004, the North Carolina Commission commenced an investigation into our North Carolina base rates and subsequently ordered us to file a general rate case to show cause why our North Carolina jurisdictional base rates should not be reduced. The rate case was filed in September 2004, and in March 2005, the North Carolina Commission approved a settlement that included a prospective $12 million annual reduction in current base rates and a five-year base rate moratorium, effective as of April 2005.

Fuel rates are still subject to change under the annual fuel cost adjustment proceedings.

Status of Electric Restructuring in Virginia

1999 VIRGINIA RESTRUCTURING ACT

The 1999 Virginia Restructuring Act established a plan to restructure the electric utility industry in Virginia. In general, this legislation provided for a transition from bundled cost-based rates for regulated electric service to unbundled cost-based rates for transmission and distribution services and to market pricing for generation services, including retail choice for our customers. The 1999 Virginia Restructuring Act addressed capped base rates, RTO participation, retail choice, stranded costs recovery and functional separation of an electric utility’s generation from its transmission and distribution operations.

Retail choice was made available to all of our Virginia regulated electric customers, commencing on January 1, 2003. We have separated our generation, distribution and transmission functions through the creation of divisions. State regulatory requirements ensure that our generation division and other divisions operate independently and prevent cross-subsidies between our generation division and other divisions. Additionally, in 2005, we became a member of PJM, an RTO, and have integrated our electric transmission facilities into the PJM wholesale electricity markets. Under the 1999 Virginia Restructuring Act, our base rates have been capped until December 31, 2010, unless modified earlier as previously discussed inRates.

2004 amendments to the 1999 Virginia Restructuring Act addressed a minimum stay exemption program, a wires charge exemption program and the development of a coal-fired generating plant in southwest Virginia.

2007 VIRGINIA RESTRUCTURING ACT AMENDMENTS

In February 2007, both houses of the Virginia General Assembly passed identical bills that would significantly change electricity restructuring in Virginia. The bills would end capped rates two years early, on December 31, 2008. After capped rates end, retail choice would be eliminated for all but individual retail customers with a demand of more than 5-Mw and a limited number of non-residential retail customers whose aggregated load would exceed 5-Mw. Also after the end of capped rates, the Virginia Commis - -

The Governor has until March 26, 2007 to sign, propose amendments to, or veto the bills. With the Governor’s signature, the bills would become law effective July 1, 2007. At this time, we cannot predict the outcome of these legislative proposals.

Retail Access Pilot Programs

Three retail access pilot programs were approved by the Virginia Commission in 2003, and continue to be available to customers. There are currently six competitive suppliers and six aggregators registered with us and licensed to supply electricity to customers in Virginia. However, the current relationship between capped rates and market prices makes switching suppliers unlikely.

Federal Regulations

Energy Policy Act of 2005 (EPACT)

In August 2005, the President of the United States signed EPACT. Key provisions of EPACT include the following:

Many of the changes Congress enacted must be implemented through public notice and proposed rule making by the federal agencies affected and this process is ongoing. We will continue to evaluate the effects that EPACT may have on our business.

Federal Energy Regulatory CommissionFEDERAL ENERGY REGULATORY COMMISSION

Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by public utilities. We sell electricity in the wholesale market under our market-based sales tarifftariffs authorized by FERC. In addition, we have FERC approval of a tariff to sell wholesale power at capped rates based on our embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside our service territory. Any such sales would be voluntary. Our salesVarious proceedings that may have a significant effect on electric transmission service rates within the PJM region are ongoing at FERC. The outcome of natural gas, liquid hydrocarbon by-products and oilthese cases cannot be determined with any certainty at this point in wholesale markets are not regulated by FERC.

As required by the Virginia Restructuring Act, we joined an RTO and, in May 2005, integrated our transmission assets into PJM.time.

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 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 the North American Electric Reliability Corporation (NERC) as the ERO beginning on January 1, 2007. In late 2006, FERC also issued an initial order approving many reliability standards, also to go into effect on January 1, 2007. FERC has proposed that beginning on June 1, 2007, entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, 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 a need for major expenditures beyond the normal course of business.

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—Nuclear Decommissioning and Note 9 to our Consolidated Financial Statements.

ItemITEM 1A. Risk FactorsRISK 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, winter storms and droughts, can be destructive, causing outages and property damage that require us to incur additional expenses.

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, may require us to incur additional expenses.

Costs of environmental compliance, liabilities and litigation could exceed our estimates, which could adversely affect our results of operations. Compliance with federal, state and local environmental laws and regulations may result in increased capital, operating and other costs, including remediation and containment expenses and monitoring obligations. In addition, we may be a responsible party for environmental clean-up at a site identified by a regulatory body. Management cannot predict with certainty the amount and timing of all future expenditures related to environmental matters because of the difficulty of estimating clean-up and compliance costs, and the possibility that changes will be made to the current environmental laws and regulations. There is also uncertainty in quantifying liabilities under environmental laws that impose joint and several liability on all potentially responsible parties.

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 1999 Virginia Restructuring Act, as amended, in 2004, our base rates (excluding, generally, a fuel factor with limited adjustment provisions, and certain other allowable adjustments) remain capped through December 31, 2010 unless sooner modified or terminated consistent with the Virginia Restructuring Act.terminated. Although the Virginia Restructuringthis 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 risks include exposure to stranded costs, future environmental compliance requirements, certain tax law changes, costs related to hurricanes or other weather events,

in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Derivatives designated under hedge accounting to the extent not fully offset by the hedged transaction can result in ineffectiveness losses. These losses primarily result from differences in the location and specifications of the derivative hedging instrument and the hedged item and could adversely affect our results of operations.

Our operations in regards to these transactions are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. These market risks are beyond our control and could adversely affect our results of operations and future growth.

For additional information concerning derivatives and commodity-based contracts, seeMarket Risk Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 7 to our Consolidated Financial Statements.

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An inability to access financial markets could affect the execution of our business plan. We rely on access to short-term money markets, longer-term capital markets and banks as significant sources of liquidity for capital requirements not satisfied by the cash flows from our operations. Management believes that we will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of our control may increase our cost of borrowing or restrict our ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy 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, 2006,2007, our senior unsecured debt is rated BBB, stablepositive outlook, by Standard & Poor’s Rating GroupRatings Services (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.

ItemITEM 1B. Unresolved Staff CommentsUNRESOLVED STAFF COMMENTS

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 2.3 million retail customer accounts, including governmental agencies, and 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.

On December 31, 2005, we completed the transfer of 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 of 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.

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municipalities.

Our businesses are managed through three primary operating segments: Delivery, Energy and Generation. 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 segment.

Delivery includes our regulated electric distribution and customer service business. Electricbusinesses. Our electric distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.

Revenue provided by our electric distribution operations is based primarily on rates established by state regulatory authorities and state law. The profitability of this business is dependent on our ability, through the rates we are permitted to charge, to recover costs and earn a reasonable return on our capital investments. Variability in earnings relates largely to changes in volumes, which are primarily weather sensitive, and changes in the cost of routine maintenance and repairs (including labor and benefits).

Energy includes our regulated electric transmission system located inserving Virginia and northeastern North Carolina. On May 1,In 2005, our electric transmission business we

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 that 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

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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 obligationsASSET 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 onin 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. In the future, ifWhen 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 the related long-lived asset. We record accretion expense, increasingaccrete the ARO liability withto reflect the passage of time. In 2006, 2005 2004 and 2003,2004, we recognized $40 million, $44 million $42 million and $38$42 million, respectively, of accretion expense, and expect to incur $47$36 million in 2006.2007.

A significant portion of our AROs relate to the future decommissioning of our nuclear facilities. At December 31, 2005,2006, nuclear decommissioning AROs, which are reported in the Generation segment, totaled $798$603 million, representing approximately 96%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 obtain from third-party expertsspecialists periodic site-specific “base year”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 estimates areescalation rates is 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, hadIn 2006, we increasedlowered the cost escalation rate assumptions used in the ARO calculation by 0.5%, the amount recognized as of December 31, 2005 for0.85% due to projected reductions in both general and decommissioning specific inflation rates, resulting in a $201 million decrease in our AROs related to nuclear decommissioning would have been $156 million higher.AROs.

No. 48 (FIN 48),Accounting for Uncertainty in Income Taxes. Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, FIN 48 establishes standards for recognition and measurement, in financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets.

ACCOUNTING STANDARDS

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Newly Adopted Accounting Standards

During 2005, 20042006 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 Operations

RESULTS OF OPERATIONS

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

Overview

2006 VS. 2005

Net income increased to $478 million. Favorable drivers include the absence of $471 million of after-tax losses incurred in 2005 vs. 2004

The combined net income contributionby the discontinued operations of our primary operating segments decreased 28% to $539 million, as compared to 2004, primarily reflectingVPEM and the absence of a lower contribution2005 charge resulting from the Generation segment. The lower contribution was largelytermination 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 congestion costs and major storm damage and service restoration costs associated with tropical storm Ernesto in September 2006.

2005 VS. 2004

Net income decreased to $10 million. Unfavorable drivers include $471 million of after-tax losses incurred by the discontinued operations of VPEM and a charge resulting from the termination of a long-term power purchase agreement. Our results were also negatively affected by the impact of higher commodity prices on fuel and purchased power expenses, primarily resulting from higher commodity prices.expenses.

Other operations and maintenance expense increased 9% to $1.0 billion, primarily reflecting:

Interest and related charges decreased 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 operations reflects the absence of losses incurred by the discontinued operations of VPEM prior to its disposition in December 2005.

2005 VS. 2004

Operating Revenue increased 6% to $5.7 billion, primarily reflecting:

The growth factors in 2007 are expected to be partially offset by:

An important development impacting the future of our Company is the passage of legislation in Virginia that would re-regulate certain elements of our business, as discussed inStatus of Electric Restructuring in Virginia underFuture Issues and Other Matters. Since competitive markets have not developed in Virginia, we are supporting legislation passed by the Virginia General Assembly in early 2007 that would create a hybrid regulatory model designed to modify the traditional regulatory method to better suit it to the financial realities of undertaking major new generation and infrastructure projects. We believe this model would continue to provide our customers with comparatively low rates and ensure our ability to build new generation and other infrastructure needed to keep pace with growing demand for electricity in Virginia. The Governor has until March 26, 2007 to sign, propose amendments to, or veto the proposed legislation. With the Governor’s signature, the legislation would become law effective July 1, 2007. At this time, we cannot predict the outcome of the legislation.

Based on these projections, we estimate that cash flow from operations will increase in 2006, as comparedSEGMENT RESULTS OF OPERATIONS

Presented below is a summary of contributions by our operating segments to 2005. Management believes this increase will provide sufficient cash flow to maintain or grow our current dividend to Dominion.net income:

Segment Results of Operations

Delivery

Presented below are operating statistics related to our Delivery includes our electric distribution system and customer service operations.operations:

mwhrs = megawatt hours

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2004 vs. 2003

Generation

Presented below are operating statistics related to our Generation includes our portfolio of electric generating facilities, power purchase agreements, and energy supply operations.operations:

The Generation segment provides electricity primarily from nuclear, coal, oil, purchased power and natural gas. Presented below is a summary of the system’s energy output by energy source.source: