Item 1. Business

GENERAL

Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. Dominion’s portfolio of assets includes approximately 27,500 MW of generation, 6,000 miles of electric transmission lines, 56,000 miles of electric distribution lines in Virginia and North Carolina, 12,000 miles of natural gas transmission, gathering and storage pipeline, 21,700 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less, and 1.3 Tcfe of proved natural gas and oil reserves. Dominion also owns the nation’s largest underground natural gas storage system, operates approximately 942 bcf of storage capacity and serves retail energy customers in twelve states.

Dominion is focused on expanding its investment in regulated electric generation, and regulated electric and natural gas transmission infrastructure within and around its existing footprint. As a result, regulated capital projects will continue to receive priority treatment in its spending plans. Dominion expects this will increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity prices. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and natural gas and oil exploration and production in the Appalachian basin of the U.S. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.

Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Virginia Power.” In North Carolina, it conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion.

The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

The term “Virginia Power” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries.

Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.

EMPLOYEES

As of December 31, 2009, Dominion had approximately 17,900 full-time employees, of which approximately 6,600 employees are subject to collective bargaining agreements. As of December 31, 2009, Virginia Power had approximately 7,400 full-time employees, of which approximately 3,300 employees are subject to collective bargaining agreements.

PRINCIPAL EXECUTIVE OFFICES

Dominion and Virginia Power’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.

WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINION AND VIRGINIA POWER

Dominion and Virginia Power file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

Dominion and Virginia Power make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion’s internet website www.dom.com, as soon as practicable after filing or furnishing the material to the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning Dominion at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Information contained on Dominion’s website is not incorporated by reference in this report.

ACQUISITIONS AND DISPOSITIONS

Following are significant acquisitions and divestitures by Dominion and Virginia Power during the last five years.

ACQUISITION OF KEWAUNEE NUCLEAR POWER STATION

In July 2005, Dominion completed the acquisition of Kewaunee, a 556 MW facility in northeastern Wisconsin for approximately $192 million in cash. The operations of Kewaunee are included in the Dominion Generation operating segment.

ACQUISITION OF USGEN NEW ENGLAND, INC. POWER STATIONS

In January 2005, Dominion completed the acquisition of three fossil-fuel fired generation facilities for $642 million in cash. The facilities include Brayton Point, a 1,551 MW facility in Somerset, Massachusetts; Salem Harbor, a 754 MW facility in Salem, Massachusetts; and Manchester Street, a 432 MW facility in Providence, Rhode Island. The operations of these facilities are included in the Dominion Generation operating segment.

ASSIGNMENT OF MARCELLUS ACREAGE

In 2008, Dominion completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage.

SALE OF E&P PROPERTIES

In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion. See Note 4 to the Consolidated Financial Statement for additional information.

In 2006, Dominion received approximately $393 million of proceeds from sales of certain gas and oil properties, primarily resulting from the sale of certain properties located in Texas and New Mexico.

The historical results of these operations are included in the Corporate and Other segment.

SALE OF MERCHANT FACILITIES

In March 2007, Dominion sold three Peaker facilities for net cash proceeds of $254 million. The Peaker facilities included the 625 MW Armstrong facility in Shelocta, Pennsylvania; the 600 MW Troy facility in Luckey, Ohio; and the 313 MW Pleasants facility in St. Mary’s, West Virginia. Following the decision to sell these assets in December 2006, the results of these operations were reclassified to discontinued operations and are presented in the Corporate and Other segment.

SALE OF DRESDEN

In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million.

SALE OF CERTAIN DCI OPERATIONS

In August 2007, Dominion completed the sale of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC) and Dallastown for approximately $30 million.

In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by DCI and in April 2008 received proceeds of $54 million, including accrued interest. As discussed in Note 25 to the Consolidated Financial Statements, Dominion deconsolidated the CDO entity as of March 31, 2008.

TRANSFER OF VIRGINIA POWER ENERGY MARKETING, INC. TO DOMINION

On December 31, 2005, Virginia Power completed a transfer of its indirect wholly-owned subsidiary, VPEM, to Dominion through a series of dividend distributions, in exchange for a capital contribution of $633 million. VPEM provides fuel, gas supply management and price risk management services to other Dominion affiliates and engages in energy trading and marketing activities. As a result of the transfer, VPEM’s results of operations were reclassified to discontinued operations in Virginia Power’s Consolidated Statements of Income and presented in its Corporate and Other segment.

SALE OF PEOPLES

In March 2006, Dominion entered into an agreement with Equitable to sell two of its wholly-owned regulated gas distribution subsidiaries, Peoples and Hope. Peoples serves approximately 358,000 customer accounts in Pennsylvania and Hope serves approximately 114,000 customer accounts in West Virginia. This sale was subject to regulatory approvals in the states in which the companies operate, as well as antitrust clearance under the HSR Act. In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. Dominion continued to seek other offers for the purchase of these utilities.

In July 2008, Dominion entered into an agreement with an indirect subsidiary of BBIFNA to sell Peoples and Hope. In May 2009, following a change in ownership of the general partner of BBIFNA and other related transactions, BBIFNA was renamed “SteelRiver Infrastructure Fund North America LP”. The sale of Peoples and Hope to the SteelRiver Buyer, an indirect subsidiary of the SteelRiver Fund, was expected to close in 2009, subject to state regulatory approvals in Pennsylvania and West Virginia. In November 2009, the Pennsylvania Commission approved the settlement entered into among Dominion, Peoples, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding, thereby approving the sale of Peoples to the SteelRiver Buyer. In December 2009, the West Virginia Commission denied the application for the sale of Hope. Dominion decided to retain Hope, but continue with the sale of Peoples. The sales price for Peoples was approximately $780 million, subject to changes in working capital, capital expenditures and affiliated borrowings. In February 2010, Dominion completed the sale of Peoples and netted after-tax proceeds of approximately $542 million. A more detailed description of the sale can be found in Note 4 to the Consolidated Financial Statements.

OPERATING SEGMENTS

Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment that includes its corporate, service company and other functions and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4 to the Consolidated Financial Statements. Corporate and Other also includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. Prior to the fourth quarter of 2009, Hope was included in Dominion’s Corporate and Other segment and its assets and liabilities were classified as held for sale. During the fourth quarter of 2009, following Dominion’s decision to retain this subsidiary, Hope was transferred to the Dominion Energy operating segment and its assets and liabilities were reclassified from held for sale.

Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Power and their respective legal subsidiaries.

A description of the operations included in the Companies’ primary operating segments is as follows:

For additional financial information on business segments, including revenues from external customers, see Notes 1 and 27 to the Consolidated Financial Statements. For additional information on operating revenue related to Dominion’s and Virginia Power’s principal products and services, see Notes 2 and 5 to the Consolidated Financial Statements.

DVP

The DVP Operating Segment of Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations. Virginia Power’s electric transmission and distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.

Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Changes in revenue are driven primarily by weather, customer growth and other factors impacting consumption such as the economy and energy conservation. Variability in earnings results from changes in rates, weather, the economy, customer growth and operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As a result, electric service reliability has improved. The metric used to measure electric service reliability (System Average Interruption Duration Index, excluding major storm events) has improved from 139 minutes at the end of 2004 to 110 minutes at the end of 2009. Customer service options are also being enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. At the end of 2009, over 800,000 of Virginia Power’s customers were signed up to manage their account on-line through dom.com, and over 2.9 million transactions were performed on-line in 2009. This reflects a transaction increase of 45% over 2008. As electric distribution continues to evolve, safety, operational performance and customer service will remain as key focal areas.

The Virginia General Assembly enacted legislation in April 2007 that instituted a modified cost-of-service rate model for the Virginia jurisdiction of Virginia Power’s utility operations, subject to base rate caps in effect through December 31, 2008. In 2009, the Virginia Commission initiated a review of Virginia Power’s base rates. A discussion of Virginia Power’s proposal in the case, including a settlement agreement to which it is a party, is contained in Electric Regulation in Virginia under Regulation.

Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by 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 in earnings results from changes in rates and the timing of property additions, retirements and depreciation.

In April 2008, FERC granted an application by Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4% on the common equity base of these operations, effective as of January 1, 2008. The FERC ruling did not materially impact the Company’s results of operations; however, the FERC-approved formula method allows Virginia Power to earn a more current return on its growing investment in electric transmission infrastructure. In addition, in August 2008, FERC granted an application by Virginia Power’s electric transmission operations requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects and approved an incentive of 1.5% for four of the projects and an incentive of 1.25% for the other seven. See Federal Regulations in Regulation for additional information.

Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are

committed to meeting NERC standards, modernizing their infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance and execution of PJM’s RTEP.

The DVP Operating Segment of Dominion includes all of Virginia Power’s regulated electric transmission and distribution operations as discussed above, as well as Dominion’s nonregulated retail energy marketing operations.

Dominion’s retail energy marketing operations compete in nonregulated energy markets and have experienced strong customer growth during the past few years. The retail business requires limited capital investment and currently employs fewer than 150 people. The retail customer base is diversified across three product lines—natural gas, electricity and home warranty services. In natural gas, Dominion has a heavy concentration of customers in markets where utilities have a long-standing commitment to customer choice. In electricity, Dominion pursues markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are customer additions, new markets/products and sales channels, and supply optimization.

COMPETITION

DVP Operating Segment—Dominion and Virginia Power

Within Virginia Power’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since its electric transmission facilities are integrated into PJM, 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. Virginia Power is seeing continued growth in new customers in its transmission and distribution operations.

DVP Operating Segment—Dominion

Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas and electricity. Customers in these markets have the right to select a retail marketer and typically do so based upon price savings or price stability; however, incumbent utilities have the advantage of long-standing relationships with their customers and greater name recognition in their markets.

REGULATION

Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission. Virginia Power’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. See State Regulations and Federal Regulations in Regulation for additional information.

PROPERTIES

Virginia Power has approximately 6,000 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Pow -

er’s 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 these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance, and exchange of capacity and energy for such facilities.

Each year, as part of PJM’s RTEP process, reliability projects are authorized. In June 2006, PJM authorized construction of numerous electric transmission upgrades through 2011. Virginia Power is involved in two of the major construction projects, which are designed to improve the reliability of service to customers and the region, and are subject to applicable state and federal permits and approvals.

In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route proposed for the line which is adjacent to, or within, existing transmission line right-of-ways. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In March 2009, the Sierra Club filed an appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the Supreme Court of West Virginia in April 2009. An appeal of the Pennsylvania Commission’s approval by the Energy Conservation Council of Pennsylvania is pending. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. In November 2009, the Virginia Supreme Court affirmed the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and, subject to the receipt of all regulatory approvals, is expected to be completed in June 2011.

In October 2008, the Virginia Commission authorized the construction of the Carson-to-Suffolk line. This project is estimated to cost $224 million and is expected to be completed in June 2011. The siting and construction of these transmission lines are subject to applicable state and federal permits and approvals.

In addition, Virginia Power’s electric distribution network includes approximately 56,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain right-of-ways that have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where right-of-ways 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 ENERGY SUPPLY

DVP Operating Segment—Dominion and Virginia Power

DVP’s supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. See Dominion Generation for additional information.

DVP Operating Segment—Dominion

The supply of electricity to serve Dominion’s retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions and its supply of gas to serve its customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.

SEASONALITY

DVP Operating Segment—Dominion and Virginia Power

DVP’s earnings vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days for DVP’s electric utility related operations does not produce the same increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

DVP Operating Segment—Dominion

The earnings of Dominion’s retail energy marketing operations also vary seasonally. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, while the demand for gas peaks during the winter months to meet heating needs.

Dominion Generation

The Dominion Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for the DVP segment’s utility customers. The generation mix is diversified and includes coal, nuclear, gas, oil and renewables. The generation facilities of Virginia Power’s electric utility fleet are located in Virginia, West Virginia and North Carolina. As discussed in Properties, Virginia Power has plans to add additional generation capacity to satisfy future growth in its utility service area.

Earnings for the Generation operating segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Due to 1999 Virginia deregulation legislation, as amended in 2004 and 2007, revenues for serving Virginia jurisdictional retail load were based on capped rates through 2008. Additionally, fuel costs for the utility fleet, 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 re-instituted beginning July 1, 2007 for Virginia jurisdictional customers. The Virginia General Assembly enacted legislation in April 2007 that returned the Virginia jurisdiction of Virginia Power’s generation operations to a modified cost-of-service rate model, subject to base rate caps in effect through December 31, 2008. As a result, Virginia Power reapplied accounting guidance for cost-based regulation to those operations in April 2007, when the legislation was enacted. In 2009, the Virginia Commission initiated a review of Virginia Power’s base rates. A discussion of

Virginia Power’s proposal in the case, including a settlement agreement to which it is a party, is contained in Electric Regulation in Virginia under Regulation. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages.

The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations described above as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets. The generation facilities of Dominion’s merchant fleet are located in Connecticut, Illinois, Indiana, Massachusetts, Pennsylvania, Rhode Island, West Virginia and Wisconsin. In the merchant generation business, Dominion is adding generation capacity through several new renewable energy projects and uprates, as discussed in Properties. The Generation operating segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as associated capacity from Dominion’s merchant generation assets.

Variability in earnings provided by Dominion’s merchant fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages electric and capacity price volatility by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements, which should help mitigate the adverse impact on earnings from declines in commodity prices, such as those experienced during 2008 and 2009. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.

COMPETITION

Dominion Generation Operating Segment—Dominion and Virginia Power

Retail choice was made available to Virginia Power’s Virginia jurisdictional electric utility customers beginning January 1, 2003; however, no significant competition developed. In April 2007, the Virginia General Assembly passed legislation ending retail choice for most of these customers effective January 1, 2009. See Regulation—State Regulations—Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation Operating Segment—Dominion

Dominion Generation’s merchant generation fleet owns and operates several facilities in the Midwest that operate within functioning RTOs. A significant portion of the output from these facilities is sold under long-term contracts, with expiration dates ranging from December 31, 2012 to August 31, 2017, and is therefore largely unaffected by competition.

Dominion Generation’s other merchant assets also operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units have a variety of short and medium-term contracts, and also compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion applies its expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to similar assets within the region.

REGULATION

Virginia Power’s utility generation fleet and Dominion’s merchant generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

For a listing of Dominion’s and Virginia Power’s generation facilities, see Item 2. Properties.

Dominion Generation Operating Segment—Dominion and Virginia Power

Based on available generation capacity and current estimates of growth in customer demand in Virginia Power’s utility service area, it will need additional generation capacity over the next ten years. Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in its core market in Virginia. As part of this program, the following projects have recently been completed or are in various stages of development:

In June 2008, Virginia Power commenced the operation of two additional natural gas-fired electric generating units (Units 3 and 4) totaling 321 MW at its Ladysmith power station to supply electricity during periods of peak demand. In addition, in April 2009, a fifth combustion turbine (Unit 5) with 160 MW of capacity commenced operations.

The Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the Virginia City Hybrid Energy Center located in Wise County, Virginia, which once operational, will generate about 585 MW. In July 2008, the SELC, on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia. In April 2009, the Virginia Supreme Court affirmed the Virginia Commission’s Final Order. In its Final Order, the Virginia Commission approved an initial return on common equity for the facility of 12.12%, consisting of a base return of 11.12% plus a 100 basis point enhancement that Virginia law provides for new conventional coal generation facili -

ties. The Virginia Commission also authorized Virginia Power to apply for an additional 100 basis point enhancement upon a demonstration that the plant is carbon-capture compatible. The enhanced return will apply to the Virginia City Hybrid Energy Center during construction and through the first twelve years of the facility’s service life.

In June 2008, the Virginia State Air Pollution Control Board approved and issued an air permit to construct and operate the Virginia City Hybrid Energy Center and also approved and issued another air permit for hazardous emissions. Construction of the Virginia City Hybrid Energy Center commenced and the facility is expected to be in operation by 2012. In August 2008, the SELC, on behalf of four environmental groups, filed Petitions for Appeal in Richmond Circuit Court challenging the approval of both of the air permits. The Richmond Circuit Court issued an Order in September 2009 upholding the initial air permit and upholding the second air permit for hazardous emissions except for one condition related to the permit limit for mercury emissions. The hazardous emissions air permit was amended by the Virginia Department of Environmental Quality in September 2009 to comply with the Richmond Circuit Court Order. The permit amendment does not impact the project. In October 2009, the SELC filed a Notice of Appeal of the court’s Order regarding the initial air permit with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. The SELC’s opening brief to the Virginia Court of Appeals was filed in January 2010. Briefing should conclude in February 2010. Oral argument will be scheduled upon the completion of briefing. A decision by the Court of Appeals is expected by the second or third quarter of 2010. The result of the appeal does not impact the project’s construction.

Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. Virginia Power and ODEC have obtained an Early Site Permit for the North Anna site from the NRC. In November 2007, Virginia Power, along with ODEC, filed an application with the NRC for a COL that references a specific reactor design and which would allow Virginia Power to build and operate a new nuclear unit at North Anna. In January 2008, the NRC accepted Virginia Power’s application for the COL and deemed it complete. In December 2008, Virginia Power terminated a long-lead agreement with its vendor with respect to the reactor design identified in its COL application and certain related equipment. A competitive process was initiated in 2009 to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to Virginia Power. If, as a result of this process, Virginia Power chooses a different reactor design, it will amend its COL application, as necessary. Virginia Power has not yet committed to building a new nuclear unit.

The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the Atomic Safety and Licensing Board of the NRC granted a request for a hearing on one of eight contentions filed by the Blue Ridge Environmental Defense League. In August 2009, the Atomic Safety and Licensing Board dismissed this contention as moot, but in November 2009 admitted a new contention filed by Blue Ridge Environmental Defense League. Virginia Power filed a motion for reconsideration of this ruling that is pending before the Atomic Safety and Licensing

Board. Absent additional contentions, the mandatory NRC hearing will be uncontested with respect to other issues. Virginia Power has a cooperative agreement with the DOE to share equally the cost of developing a COL that references a specific reactor technology; however, this agreement may not remain in effect going forward if Virginia Power chooses a different reactor technology.

In June 2008, the DOE issued a solicitation announcement inviting the submission of applications for loan guarantees from the DOE under its Loan Guarantee Program in support of debt financing for nuclear power facility projects in the U.S. In May 2009, the DOE announced the names of four energy companies that were selected to begin negotiations for federal loan guarantees for proposed new nuclear units in the U.S. Although Virginia Power, in a two-part process, submitted an application for a federal loan guarantee for the proposed North Anna unit, the Company was not among those selected. While Virginia Power can provide no assurance, because of the dynamic nature of the market for new nuclear units, there may be other opportunities to secure a loan guarantee with the DOE.

In March 2008, Virginia Power purchased the Bear Garden power station development project which, once constructed, will generate about 580 MW. The air and water permits for the combined-cycle, natural gas-fired power station have been amended to allow for Virginia Power’s project designs and schedules. Authorization was granted by the Virginia Commission in March 2009 to build the proposed combined-cycle, natural gas-fired power station and transmission interconnection line for an estimated $619 million, excluding financing costs. A gas pipeline is scheduled to be constructed by Columbia Gas of Virginia to provide gas supply to the power station.

In March 2008, Virginia Power also purchased a power station development project in Warren County, Virginia for future development. If developed, the project will involve the construction of a combined-cycle, natural gas-fired power station expected to generate more than 600 MW of electricity and will be subject to necessary regulatory approvals.

In April 2008, Virginia Power announced a joint effort with BP to evaluate wind energy projects, which, if completed, would increase the renewable energy capacity of Virginia Power’s utility generation fleet.

Dominion Generation Operating Segment—Dominion

In addition to the Powering Virginia projects, Dominion has invested in several wind farm projects. In December 2006, Dominion acquired a 50% interest in NedPower. NedPower consists of two phases totaling 264 MW. The first (164 MW) and second (100 MW) phases began commercial operations in July and December 2008, respectively.

In January 2008, Dominion acquired a 50% interest in Fowler Ridge. The first phase consisting of 300 MW achieved full commercial operations in March 2009. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, Dominion reached an agreement with BP to split the development assets of the final 350 MW phase. Under

the agreement, Dominion will own 150 MW of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.

In April 2008, Dominion announced plans to develop Prairie Fork. Construction of this wind turbine facility is subject to receipt of all necessary permits and approvals.

In 2008 and 2009, Dominion completed two uprates totaling 120 MW at Fairless. Additionally, in January 2009, Dominion successfully implemented an NRC-approved 7% uprate at Unit 3 of Millstone. This increased the unit’s output by approximately 77 MW from 1,150 MW to 1,227 MW, or enough to power an additional 60,000 homes.

SOURCES OF ENERGY SUPPLY

Dominion Generation Operating Segment—Dominion and Virginia Power

Dominion Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.

Nuclear Fuel—Dominion Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable 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. Additional fuel is purchased as required to ensure optimal cost and inventory levels.

Fossil Fuel—Dominion Generation primarily utilizes coal, oil and natural gas in its fossil fuel plants. Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from both domestic and international suppliers.

Dominion Generation’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.

Dominion Generation manages a portfolio of natural gas transportation contracts (capacity) that allows flexibility in delivering natural gas to its gas turbine fleet, while minimizing costs.

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

Dominion Generation also occasionally purchases electricity from the PJM, ISO-NE and MISO spot markets to satisfy physical forward sale requirements as part of its merchant generation operations.

Dominion Generation Operating Segment—Virginia Power

Presented below is a summary of Virginia Power’s actual system output by energy source:

SEASONALITY

Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days for Virginia Power’s utility operations does not produce the same increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

NUCLEAR DECOMMISSIONING

Dominion Generation Operating Segment—Dominion and Virginia Power

Virginia Power has a total of four licensed, operating nuclear reactors at its Surry and North Anna power stations in Virginia.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the 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.

Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.

The total estimated cost to decommission Virginia Power’s four nuclear units is $2.2 billion in 2009 dollars and is primarily based upon site-specific studies completed in 2009. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Virginia Power expects to decommission the Surry and North Anna units during the period 2032 to 2067.

Dominion Generation Operating Segment—Dominion

In addition to the four nuclear units discussed above, Dominion has three licensed, operating nuclear reactors, two at Millstone in Connecticut and one at Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. As part of Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. The total estimated cost to decommission Dominion’s eight units is $4.5 billion in 2009 dollars and is primarily based upon site-specific studies completed in 2009. For the Millstone and Kewaunee operating units, the current cost estimate assumes decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Millstone Unit 1 is not in service and selected minor decommissioning activities are being performed. This unit will continue to be monitored until full decommissioning activities begin for the remaining Millstone operating units. Dominion expects to start minor decommissioning activities at Millstone Unit 2 in 2035, with full decommissioning of Millstone Units 1, 2 and 3 during the period 2045 to 2069. In August 2008, Dominion filed an application with the NRC to renew the Kewaunee operating license. A renewal would permit Kewaunee to operate through December 21, 2033 with full decommissioning of Kewaunee during the period 2033 to 2065. The NRC docketed the application in October 2008. No requests for a hearing were received on the application, although there will be opportunities for public input as the NRC conducts its review of the application. The NRC’s schedule contemplates completion of the uncontested proceeding in February 2011.

The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table.

Dominion Energy

Dominion Energy includes Dominion’s Ohio and West Virginia regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities, regulated LNG operations and Appalachian E&P operations. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.

The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. Revenue provided by Dominion’s regulated gas transmission and storage, and LNG operations is based primarily on rates established by FERC. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio and West Virginia. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and maintenance expenditures, as well as changes in rates and the demand for services, which can be dependent on weather, changes in commodity prices and the economy.

Revenue from gas transportation, gas storage, and LNG storage and regasification services are largely based on firm, fee-based contractual arrangements.

In October 2008, Dominion East Ohio implemented a rate case settlement which began a transition to a Straight Fixed Variable rate design. Under this rate design, Dominion East Ohio recovers a larger portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, Dominion East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.

Dominion’s Appalachian E&P business generates income from the sale of natural gas and oil it produces from its reserves, including fixed-term overriding royalty interests formerly associated with its VPP agreements (VPP royalty interests) discussed in Note 11 to the Consolidated Financial Statements. Variability in earnings relates to changes in commodity prices, which are largely market-based, production volumes, which are impacted by numerous factors including drilling success and timing of development projects, and drilling costs which may be impacted

by drilling rig availability and other external factors. Production from VPP royalty interests declined significantly due to the expiration of these interests in February 2009. Dominion manages commodity price volatility by hedging a substantial portion of its near-term expected production, which should help mitigate the adverse impact on earnings from declines in gas and oil prices, such as those experienced in 2008 and 2009. These hedging activities may require cash deposits to satisfy collateral requirements. Dominion’s Appalachian E&P business added 138 bcfe to its gas and oil reserves as a result of its drilling program during 2009, as compared to production of 50 bcfe in 2009, excluding production from VPP royalty interests.

Earnings from Dominion Energy’s other nonregulated business, producer services, are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.

COMPETITION

Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. Dominion also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion to tailor its services to meet the needs of individual customers.

Retail competition for gas supply exists to varying degrees in the two states in which Dominion’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion has offered an Energy Choice program to customers, in cooperation with the Ohio Commission. West Virginia does not require customer choice in its retail natural gas markets at this time. See Regulation—State Regulations—Gas for additional information.

REGULATION

Dominion Energy’s natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion Energy’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio and West Virginia Commissions. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

Dominion Energy’s gas distribution network is located in the states of Ohio and West Virginia. This network involves approximately 21,700 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owner of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

Dominion Energy has approximately 12,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 942 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at its Cove Point LNG facility. Dominion Energy has about 134 compressor stations with more than 747,000 installed compressor horsepower.

Dominion Energy also owns about 1.3 Tcfe of proved natural gas and oil reserves and produces approximately 137 million cubic feet equivalent of natural gas and oil per day from its leasehold acreage and facility investments in Appalachia.

In 2006, FERC approved the proposed expansion of Dominion’s Cove Point terminal and DTI pipeline and the commencement of construction of the project. The expansion project included the installation of two new LNG storage tanks at Dominion’s Cove Point terminal, each capable of storing 160,000 cubic meters of LNG, pumps, gas-turbine generators, and vaporization capacity to increase the terminal send-out by 800,000 dekatherms per day. Dominion installed 48 miles of 36-inch pipeline to increase the terminal take-away capacity to approximately 1,800,000 dekatherms per day. In addition, Dominion’s DTI gas pipeline and storage system was expanded by building approximately 120 miles of pipeline, two new compressor stations in Pennsylvania and other upgrades to other compressor stations in West Virginia and New York. The DTI facilities associated with the Cove Point expansion project were placed into service in December 2008, the Cove Point LNG terminal expansion was placed into service in January 2009 and the remainder of the expanded Cove Point facilities were placed into commercial service in March 2009.

In September 2008, Dominion completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage. Following this transaction, Dominion controls drilling rights on approximately 450,000 acres in the Marcellus Shale formation. Dominion plans to monetize its remaining acreage within the next two years in order to reduce or eliminate its equity financing needs.

DTI has announced the proposed development of a gas pipeline project, known as the Appalachian Gateway Project, which is designed to transport gas on a firm basis out of the Appalachian Basin in West Virginia and southwestern Pennsylvania to DTI’s interconnect with Texas Eastern Transmission Corporation at Oakford, Pennsylvania. An open season for the project concluded in September 2008. The project is fully subscribed under long

term binding agreements. The Appalachian Gateway Project is expected to be fully placed into service by the fall of 2012.

Dominion has announced the Gathering Enhancement Project, a $253 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through Dominion’s West Virginia system. Construction started in 2009 and will be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.

Dominion has also announced the proposed development of the Keystone Connector Project, a joint venture with The Williams Companies that would transport new natural gas supplies from the Appalachian Basin to Transcontinental Gas Pipe Line Corporation’s Station 195, providing access to markets throughout the eastern U.S. Dominion is currently in discussions regarding the continued development of the Keystone Connector Project. Project timing is subject to producer drilling plans in the Appalachian Basin, as well as customer demand throughout the mid-Atlantic and Northeast regions.

SOURCES OF ENERGY SUPPLY

Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major interstate gas pipelines, including the Rockies Express East pipeline and large markets in the Northeast and mid-Atlantic regions. Dominion’s pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.

Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity. Dominion Energy’s natural gas supply is obtained from various sources including Dominion’s own production, less royalties, purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers.

SEASONALITY

Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March, however implementation of the Straight Fixed Variable rate design at Dominion East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipelines and storage business can also be weather sensitive. Dominion Energy’s Appalachian E&P business can be impacted by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for Dominion’s unhedged natural gas and oil production, can be impacted by seasonal weather changes, the effects of weather on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of

commodities that it transports, stores and actively markets and trades.

Corporate and Other

Corporate and Other Segment—Virginia Power

Virginia Power’s Corporate and Other segment primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

Corporate and Other Segment—Dominion

Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4 to the Consolidated Financial Statements. Operations disposed of during 2007 included all of Dominion’s non-Appalachian E&P operations, three natural gas-fired merchant generation peaker facilities and certain DCI operations. Operations disposed of during 2008 included certain DCI operations. Operations to be disposed of at December 31, 2009 include Peoples, which Dominion sold in February 2010. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

ENVIRONMENTAL STRATEGY

Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of five major elements:

Conservation plays a role in meeting the growing demand for electricity. Virginia re-regulation legislation enacted in 2007 provides incentives for energy conservation and sets a goal to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. A description of Virginia Power’s conservation and load management programs is detailed below.

Dominion and Virginia Power are working to improve their own energy efficiency, both in using less fuel to produce the same amount of energy and to use less energy in their operations. Recent uprates of their facilities have resulted in significant increases in generation capacity and lower emissions to meet the needs of their customers.

Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have

passed legislation setting targets for renewable power. Virginia Power is committed to meeting Virginia’s goals of 12% renewable power by 2022 and 15% by 2025 and North Carolina’s renewable portfolio standard of 12.5% by 2021. In July 2009, Virginia Power applied to the Virginia Commission for approval to participate in Virginia’s renewable energy portfolio standard program. The application identifies a Renewable Portfolio Standard Plan for meeting Virginia’s goals and includes a combination of existing renewable energy sources, development of new renewable energy facilities and purchase of renewable energy certificates. Virginia Power also anticipates using at least 10% biomass (woodwaste) at the Virginia City Hybrid Energy Center.

In addition, Dominion is a 50% owner of the NedPower wind energy facility in Grant County, West Virginia. Dominion’s share of this project produces 132 MW of renewable energy. Dominion has also acquired a 50% interest in a joint venture with BP to develop the Fowler Ridge wind-turbine facility in Benton County, Indiana. The first phase with a generating capacity of 300 MW reached full commercial operations in March 2009. Dominion has a long-term agreement with the joint venture to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, Dominion reached an agreement with BP to split the development assets of the final 350 MW phase. Under the agreement with BP, Dominion will own 150 MW of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.

Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in the core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability; increased technological and fuel diversity; and a reduction in the CO₂ emission intensity of its generation fleet. A critical aspect of the Powering Virginia program is the extent to which Virginia Power seeks to reduce the carbon intensity of its 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 capture and storage. There is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store GHG emissions. There are six generally recognized GHGs including CO₂, methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. Given that new generation units have useful lives of up to 55 years, Virginia Power will give full consideration to CO₂ and other GHG emissions when making long-term decisions. See Dominion Generation—Properties for more information.

Virginia Power plans to make a significant investment in improving the capabilities and reliability of its electric transmission and distribution system. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future. See Global Climate Change under Regulations for more information.

In further support of the Companies’ environmental strategy, Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules

related to our operations. Additional information related to our environmental compliance obligations can be found in Note 23 to the Consolidated Financial Statements.

Energy Efficiency and Peak Shaving Programs

In July 2009, Virginia Power filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of Virginia Power’s retail customers by ten percent of what was consumed in 2006. Virginia Power expects to launch the DSM programs in early 2010, subject to approval by the Virginia Commission and the North Carolina Commission, as applicable.

A key component of the plan is the demonstration of “smart grid” technologies that are designed to enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. Dependent upon the outcome of demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is expected to lead to improvements in service reliability and the ability of customers to monitor and control their energy use. Additionally, programs in the DSM plan include:

REGULATION

Dominion and Virginia Power are subject to regulation by the Virginia Commission, North Carolina Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and other federal, state and local authorities.

State Regulations

ELECTRIC

Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.

Virginia Power holds certificates of public convenience and necessity which authorize it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, Virginia Power may not construct or incur financial commitments for construction of any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina

Commission regulate Virginia Power’s transactions with affiliates, transfers of certain facilities and the issuance of securities.

Electric Regulation in Virginia

In March 2009, Virginia Power filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also included a portion of costs discussed further in Federal Regulations. In a final order in June 2009, the Virginia Commission approved recovery of approximately $218 million through Rider T, which includes approximately $150 million of transmission-related costs that were traditionally incorporated in base rates, plus an incremental increase of approximately $68 million. The Virginia Commission also ruled that approximately $10 million that the Company had proposed to collect in Rider T would be more appropriately recovered through base rates, and those costs have been incorporated into the Company’s revised base rate filing that was submitted in July 2009. Rider T became effective on September 1, 2009, and increased a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.11 per month.

Virginia Power also has filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs, including one peak-shaving program and ten energy efficiency programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of the Company’s retail customers by ten percent of what was consumed in 2006. In February 2010, the Virginia Commission concluded an evidentiary hearing to consider the DSM programs and the related recovery. The Company has requested approval of two rate adjustment clauses for the associated cost recovery to be effective April 1, 2010. Specifically, the two rate adjustment clauses for recovery from Virginia jurisdictional customers represent an annual net increase in costs of approximately $48 million for the period April 1, 2010 to March 31, 2011. If approved by the Virginia Commission, the rate adjustment clauses will be expected, on a combined basis, to increase a typical 1,000 kWh residential bill by approximately $0.91 per month. The Regulation Act gives the Virginia Commission until the end of March 2010 to act on Virginia Power’s application.

In March 2009, Virginia Power filed with the Virginia Commission its first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to Rider S, plus the 100 basis point enhancement for construction of a new coal-fired generation facility, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009, at which Virginia Power presented a proposed Stipulation and Recommendation that, among other things, would reduce the increase in the revenue requirement by approximately $8 million to $91 million. In December 2009, the hearing examiner’s report

was issued recommending approval of the Rider S increase as set forth in the proposed Stipulation, and thereafter the Virginia Commission approved the Rider S increase consistent with this recommendation. The Rider S revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding.

In March 2009, Virginia Power also filed a petition with the Virginia Commission for recovery of approximately $77 million of construction-related financing costs associated with Bear Garden through the initiation of Rider R. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a 100 basis point enhancement for construction of a combined-cycle facility, as authorized by the Regulation Act, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009. In Virginia Power’s post-hearing brief, it unilaterally agreed to reduce the revenue requirement by $4 million to $73 million. In December 2009, the Virginia Commission approved Rider R with the $73 million revenue requirement for 2010. The Rider R revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding. In accordance with the Virginia Commission’s approval of Rider R, the enhanced return will apply to the Bear Garden facility during construction and through the first ten years of the facility’s service life.

In March 2009, Virginia Power filed its Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh, or approximately $3.64 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was held on September 1, 2009. Consistent with a proposal made by the Company at the hearing in September 2009, the Virginia Commission issued an interim fuel order, effective October 1, 2009, further reducing the fuel factor by approximately $103 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.529 cents per kWh to 3.310 cents per kWh, or approximately $2.19 per month for a typical 1,000 kWh Virginia jurisdictional residential customer’s bill. The cumulative decrease in the fuel factor for the period July 1, 2009 through June 30, 2010 reflects lower projected fuel expenses and a prospective credit against fuel expenses of certain FTRs allocated to the Company. In December 2009, the Virginia Commission issued another interim order decreasing Virginia Power’s fuel factor by approximately $119 million from 3.310 cents per kWh to 2.927 cents per kWh, a reduction of approximately $3.83 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill, for service rendered on and after January 1, 2010. The Virginia Commission has not yet issued a final order.

Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. In response, Virginia Power submitted base rate filings and accompanying schedules during 2009 to the Virginia

Commission, which, as amended, propose to increase its Virginia jurisdictional base rates by approximately $250 million annually. Virginia Power’s initial March 2009 filing proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on Virginia Power’s generating plant performance, customer service, and operating efficiency, resulting in a total ROE request of 13.5%. In July 2009, in response to rulings by the Virginia Commission relating to the appropriate rate year and capital structure to be used in the Company’s base rate review, Virginia Power submitted a revised filing reflecting a number of adjustments, including an upward adjustment of 50 basis points in the proposed ROE. The base rate increase became effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission and increases a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $5.22 per month.

In November 2009, Virginia Power and the Office of the Attorney General of Virginia, Division of Consumer Counsel, and certain other interested parties, filed a Stipulation and Recommendation for consideration and requested approval by the Virginia Commission that would resolve the pending proceeding to set base rates in Virginia, the Virginia fuel case proceeding and the authorized ROE for the rate adjustment clauses for the Virginia City Hybrid Energy Center, Bear Garden and the DSM programs. The November 2009 Stipulation entails, among other things, a partial refund of 2008 revenues and other amounts, an authorized ROE applicable to base rates of 11.9%, an authorized ROE applicable to the Virginia City Hybrid Energy Center and Bear Garden rate adjustment clauses of 12.3% and continuation of Virginia Power’s base rates in existence prior to September 1, 2009. An evidentiary hearing in the base rate review has been completed, at which evidence relating to both Virginia Power’s request for a base rate increase and the November 2009 Stipulation was presented. Not all of the parties to the base rate review or the related proceedings supported the November 2009 Stipulation. In February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission. As compared to the November 2009 Stipulation, the February 2010 Stipulation has the support of all parties, including the Staff of the Virginia Commission and reflects an increase in the amounts to be refunded to customers. Virginia Power’s 2009 results include a charge representing its best estimate of the probable outcome of this matter, which is discussed further in Note 14 to the Consolidated Financial Statements. Outcomes of the base rate review could include adoption of the terms of the February 2010 Stipulation, or alternatively, a rate increase, a rate decrease, or a partial refund of 2008 earnings deemed more than 50 basis points above the authorized ROE.

If the Virginia Commission’s future rate actions, including actions relating to Virginia Power’s 2009 base rate review, DSM programs, recovery of Virginia fuel expenses, and additional rate adjustment clause filings differ materially from Virginia Power’s expectations it could adversely affect its results of operations, financial condition and cash flows.

North Carolina Regulation

In 2004, the North Carolina Commission commenced a review of Virginia Power’s North Carolina base rates and subsequently ordered Virginia Power to file a general rate case to show cause

why its 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 annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.

In February 2010, Virginia Power filed an application with the North Carolina Commission to increase its electric retail rates in North Carolina by approximately $46 million effective January 2011. The requested rate increase would consist of a base rate increase of approximately $29 million and approximately $17 million in purchased power costs to be recovered by means of the existing pass-through fuel adjustment charge. These purchased power costs have previously been considered part of the Company’s cost of service for recovery through base rates. The application entails a proposed ROE of 11.9%. The proposed base rate increase of $29 million would increase a typical 1,000 kWh North Carolina jurisdictional customer’s bill by approximately 9% or $8.96 per month when compared to residential bills under the currently approved rates. If the entire $17 million increase related to purchased power costs were to be approved for recovery in the 2011 fuel adjustment charge, and if none of those costs are offset by reductions in costs for other fuel types, the additional impact on residential customer bills would be approximately 5% or $4.94 per month. It is anticipated that a public hearing on the proposed base rate increase will be consolidated with the Company’s annual fuel adjustment proceeding in the fourth quarter of 2010 so as to facilitate a North Carolina Commission order in both matters before the end of 2010.

GAS

Dominion’s gas distribution services are regulated by the Ohio Commission, the Pennsylvania Commission and the West Virginia Commission.

Status of Competitive Retail Gas Services

Each of the three states in which Dominion has gas distribution operations has enacted or considered legislation regarding a competitive deregulation of natural gas sales at the retail level.

Ohio—Ohio has not enacted legislation requiring supplier choice for residential or commercial natural gas consumers. However, in cooperation with the Ohio Commission, Dominion has offered retail choice to residential and commercial customers. At December 31, 2009, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, Dominion East Ohio implemented a pilot program approved by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program. Under the pilot program, Dominion East Ohio entered into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement. This Standard Service Offer pricing mechanism replaced the traditional gas cost recovery rate with a monthly market price that eliminated the true-up adjustment, making it easier for customers to compare and switch to competitive suppliers if they so choose.

In June 2008, the Ohio Commission approved a settlement filed in response to Dominion East Ohio’s application seeking

approval of Phase 2 of its plan to restructure its commodity service. Under that settlement, the existing Standard Service Offer program was continued through March 2009 with an update to the fixed rate adder to the NYMEX price. Starting in April 2009, Dominion East Ohio buys natural gas under the Standard Service Offer program for customers not eligible to participate in the Energy Choice program, but places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills. Subject to ultimate Ohio Commission approval, Dominion East Ohio may exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. Dominion East Ohio will continue to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.

Pennsylvania—In Pennsylvania, supplier choice is available for all residential and small commercial customers of Peoples. At December 31, 2009, approximately 94,000 of Peoples’ 358,000 residential and small commercial customers had opted for Energy Choice in the Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

West Virginia—At this time, West Virginia has not enacted legislation to require customer choice in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.

Rates

Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Ohio, Pennsylvania and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs. In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one, three or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

In the fourth quarter of 2008, the Ohio Commission approved an approximately $41 million annual revenue increase and an 8.49% allowed rate of return on rate base for Dominion East Ohio, which were reflected in revised rates commencing December 22, 2008.

In October 2008, Hope filed a request with the West Virginia Commission for an increase in the base rates it charges for natural gas service. The requested new base rates would have increased Hope’s revenues by approximately $34 million annually. In November 2009, the West Virginia Commission authorized an approximately $9 million increase in base rates.

Regulatory Approval of Sale of Peoples

In September 2008, Dominion and BBIFNA each filed a Premerger Notification and Report Form with the U.S. Department of Justice and the Federal Trade Commission under the HSR Act. In October 2008, the mandatory waiting period under the HSR Act related to the proposed sale of Peoples and Hope to the SteelRiver Buyer expired. In September 2009, Dominion and the SteelRiver Fund each filed a renewed Premerger Notification and Report Form with the U.S. Department of Justice and Federal Trade Commission. In October 2009, Dominion and the SteelRiver Fund were granted early termination of the mandatory waiting period under the HSR Act.

In September 2008, Peoples, Dominion and the SteelRiver Buyer filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by the SteelRiver Buyer of all of the stock of Peoples. In September 2009, Peoples, Dominion, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding reached a settlement on issues involved in the Peoples sale. In November 2009, the Pennsylvania Commission approved the settlement, thereby approving the sale of Peoples to the SteelRiver Buyer.

In October 2008, Hope, Dominion and the SteelRiver Buyer filed a joint petition seeking West Virginia Commission approval of the purchase by the SteelRiver Buyer of all of the stock of Hope. In December 2009, the West Virginia Commission denied the application for the sale of Hope.

Dominion decided to retain Hope, but continue with the sale of Peoples, which closed in February 2010.

Federal Regulations

EPACT AND THE REPEAL OF PUHCA

EPACT was signed into law in August 2005. Among other things, EPACT repealed PUHCA, which regulated many significant aspects of a registered holding company system, such as Dominion’s. As a result of PUHCA’s repeal, utility holding companies, including Dominion’s system, are no longer limited to a single integrated public utility system. Further, utility holding companies are no longer restricted from acquiring businesses that may not be related to the utility business. Jurisdiction over certain holding company related activities has been transferred to the FERC, including the issuance of securities by public utilities, the acquisition of securities of utilities, the acquisition or sale of certain utility assets, and the merger with another electric utility or holding company. In addition, both FERC and state regulators are permitted to review the books and records of any company within a holding company system.

EPACT contains key provisions affecting the electric power industry. These provisions include tax changes for the utility industry, incentives for emissions reductions and federal insurance and incentives to build new nuclear power plants. It gives the FERC “backstop” transmission siting authority, as well as increased utility merger oversight. The law also provides incentives and funding for clean coal technologies and initiatives to voluntarily reduce GHG emissions. FERC has issued regulations implementing EPACT. Dominion and Virginia Power do not expect compliance with these regulations to have a material adverse impact on their financial condition or results of operations.

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary. In May 2005, FERC issued an order finding that PJM’s existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings on the matter. In January 2008, FERC affirmed an earlier decision that the PJM transmission rate design for existing facilities had not become unjust and unreasonable. For recovery of costs of investments of 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 500 kV, 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 U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded that issue back to FERC for further proceedings. Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand.

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

Dominion and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.

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

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

In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4% on the common equity base of these operations, effective as of January 1, 2008. The formula rate is designed to cover the expected cost of service for each calendar year and is trued up based on actual costs. While other transmission owners in the PJM region use a formula rate based on historic costs, Virginia Power’s formula rate is based on projected costs. The FERC ruling did not materially impact Virginia Power’s results of operations; however, the FERC-approved formula method allows Virginia Power to earn a more current return on its growing investment in electric transmission infrastructure.

In July 2008, Virginia Power filed an application with FERC requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 150 basis points or 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 125 basis points or 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008 and rehearing is pending. Virginia Power cannot predict the outcome of the rehearing.

In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Commission, New Jersey Board of Public Utilities and several other organizations representing consumers in the PJM region (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. Dominion and Virginia Power cannot predict the outcome of the appeal.

In December 2008, FERC approved the Companies’ DRC request to become effective January 1, 2009, which allows recovery of approximately $153 million of Dominion’s RTO costs, including $140 million at Virginia Power, that were deferred due to a statutory base rate cap established under Virginia law. In June 2009, the Virginia Commission approved full recovery of the DRC from Virginia Power’s retail customers through Rider T. Recovery of the DRC began September 1, 2009. In July 2009, FERC issued an order denying the Office of the Attorney General of Virginia and the Virginia Commission’s requests for rehearing of its December 2008 order. Notices of appeal were filed in September 2009 at the U.S. Court of Appeals for the Fourth Circuit and the appeal is currently pending. In the fourth quarter of 2009, Dominion and Virginia Power wrote off substantially all of these regulatory assets, since recovery is no longer probable based on the proposed settlement of Virginia Power’s rate case proceedings discussed further in Note 14 to the Consolidated Financial Statements.

Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI, DCP and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

Dominion’s interstate gas transmission and storage activities are generally conducted on an “open access” basis, in accordance with certificates, tariffs and service agreements on file with FERC.

Dominion is also subject to the Pipeline Safety Act of 2002 (2002 Act), which mandates inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion has evaluated its natural gas transmission and storage properties, as required by the Department of Transportation regulations under the 2002 Act, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.

In May 2005, FERC approved a comprehensive rate settlement with Dominion’s subsidiary, DTI, and its customers and interested state commissions. The settlement, which became effective July 1, 2005, revised Dominion’s natural gas transmission rates and reduced fuel retention levels for storage service customers. As part of the settlement, DTI and all signatory parties agreed to a rate moratorium through June 30, 2010.

In December 2007, DTI and the Independent Oil and Gas Association of West Virginia, Inc. reached a settlement agreement on DTI’s gathering and processing rates for the period January 1, 2009 through December 31, 2011. This settlement maintained the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In connection with the settlement, DTI has committed to invest at least $20 million annually in Appalachian gathering-related assets. The new rates have been approved by FERC as negotiated rates.

Environmental Regulations

Each of Dominion’s and Virginia Power’s operating segments faces substantial laws, 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 expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), 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 Companies. Dominion and Virginia Power have applied for or obtained the necessary environmental permits for the operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.

GLOBAL CLIMATE CHANGE

General

In recent years there has been increased national and international attention to GHG emissions and their relationship to climate change, which has resulted in federal, regional and state legislative or regulatory action in this area. Dominion and Virginia Power support national climate change legislation to provide a consistent, economy-wide approach to addressing this issue and are taking action to protect the environment and address climate change while meeting the future needs of their growing service territory. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters.

Dominion developed a more comprehensive GHG inventory for calendar year 2008. For Dominion Generation, Dominion’s and Virginia Power’s direct CO₂ equivalent emissions, based on equity share (ownership), were approximately 56 million metric tonnes and 33 million metric tonnes, respectively, in 2008. For the DVP operating segment’s electric transmission and distribution operations, direct CO₂ equivalent emissions were approximately 0.2 million metric tonnes. DTI’s (including Dominion’s Cove Point LNG facility) direct CO₂ equivalent emissions were approximately 2.5 million metric tonnes, Dominion East Ohio’s direct CO₂ equivalent emissions were approximately 1.4 million metric tonnes and Dominion E&P’s direct CO₂ equivalent emissions were approximately 0.7 million metric tonnes. While the Companies do not have final 2009 emissions data, they do not expect a significant variance in emissions from 2008 amounts. With respect to electric generation, primary facility stack emissions of CO₂ from carbon based fuel combustion are directly measured via continuous emissions monitor system methods set forth under 40 CFR Part 75 of the United States Code. For those emission sources not covered under 40 CFR Part

75, and for methane and nitrous oxide emissions, quantification is based on fuel combustion, higher heating values, emission factors, and global warming potentials as specified in the new EPA Mandatory Reporting of Greenhouse Gases Rule, effective December 2009. Although the reporting rule does not apply until calendar year 2010 emissions, Dominion and Virginia Power have proactively implemented the data collection methodologies specified in the rule. For the DVP operating segment’s electric transmission and distribution emissions, the protocol used was The Climate Registry. For Dominion’s natural gas businesses, combustion related emissions were calculated using the EPA Mandatory Reporting of Greenhouse Gases Rule as described above. For DTI, the protocol used to calculate the non-combustion related emissions reported above was Greenhouse Gas Emission Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1—GHG Estimation Methodologies and Procedures—Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America. For Dominion East Ohio, the protocol used to calculate the non-combustion related emissions was the American Gas Association’s April 2008 Greenhouse Emissions Estimation Methodologies and Procedures for Natural Gas Distribution Operations. For Dominion E&P emissions, the protocol used was the American Petroleum Institute August 2009 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry.

Climate Change Legislation and Regulation

See Note 23 to the Consolidated Financial Statements for information on climate change legislation and regulation.

Physical Risks

Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Additionally, droughts can result in reduced water levels that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level.

Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions

While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts and are working toward achieving the standards established by existing state regulations as set forth above. The Companies have an integrated strategy for reducing GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, hydro and renewable energy, investing in renewable energy projects, and promoting energy conservation and efficiency efforts. See Environmental Strategy above for a description of Dominion and

Virginia Power’s strategy for reducing GHG emission intensity. Some recent efforts that have or are expected to reduce the Companies’ carbon intensity include:

While, upon entering service, Virginia Power’s new Virginia City Hybrid Energy Center, which is currently under construction in Southwest Virginia, will be a new source of GHG emissions, Virginia Power has taken steps to minimize the impact on the environment. The new plant is expected to use at least ten percent biomass for fuel and was designed to be carbon-capture compatible, meaning that technology to capture CO₂ can be added to the station when it becomes commercially available. Also, Virginia Power has announced plans to convert its coal units at Bremo power station to natural gas, contingent upon the Virginia City Hybrid Energy Center entering service and receipt of necessary approvals. It is currently estimated that the Virginia City Hybrid Energy Center will have the potential to emit about 4.8 million metric tonnes of direct CO₂ emissions in a year assuming a 100% capacity factor and 100% coal-fired operation. Actual emissions will depend on the capacity factor of the facility, and the extent to which biomass is burned. See Dominion Generation—Properties for more information on the projects above, as well as other projects under current development.

Since 2000, the Companies have tracked the emissions of their electric generation fleet. Their electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2008, Dominion and Virginia Power’s electric generating fleet (based on ownership percentage) reduced their average CO₂ emissions rate per MWh of energy

produced from electric generation by about 15% and 8%, respectively. During such time period the capacity of Dominion and Virginia Power’s electric generation fleet has grown.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of nuclear power stations, which are part of the Dominion Generation segment, are 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, it could result in substantial increases in the cost of operating and maintaining Dominion’s and Virginia Power’s nuclear generating units.

The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation—Nuclear Decommissioning and Note 10 to the Consolidated Financial Statements.

SPENT NUCLEAR FUEL

Under provisions of the Nuclear Waste Policy Act of 1982, Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. A trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. On October 15, 2008, the Court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at its Surry and North Anna power stations and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Dominion’s Millstone power station through June 30, 2006. Judgment was entered by the Court on October 28, 2008. In December 2008, the government appealed the judgment to the U. S. Court of Appeals for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s request to stay the appeal. With the exception of one case, the Federal Circuit has issued such stays in all other currently pending appeals from spent fuel damages awards. In November 2009, Dominion and Virginia Power filed a motion to lift the stay and the government has opposed this motion. Once the stay is lifted, briefing on the appeal will take place. Payment of any damages will not occur until the appeal process has been resolved. Dominion and Virginia Power cannot predict the outcome of this matter; however, in the event that they recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on their results of operations.

A lawsuit was also filed for Dominion’s Kewaunee power station, and that lawsuit is presently stayed through March 15, 2010. The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Item 1A. Risk Factors

Dominion’s and Virginia Power’s businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number of these factors have been identified 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, see Forward-Looking Statements in Item 7. MD&A.

Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Additionally, droughts can result in reduced water levels that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level.

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

Virginia Power 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 Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. If Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to sanctions, including substantial monetary penalties.

Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws could adversely affect their cash flow and profitability. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environ -

mental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, they could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Power expect that they will remain significant in the future. Costs of compliance with environmental regulations could adversely affect their results of operations and financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets Dominion and Virginia Power operate increases. Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations related to emissions. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties.

If federal and/or state requirements are imposed on energy companies mandating further emission reductions, including limitations on GHG emissions and reductions in SO₂, NO_x and mercury emissions and other environmental requirements relating to coal ash disposal and cooling water, such requirements may result in compliance costs that alone or in combination could make some of Dominion’s and Virginia Power’s electric generating units uneconomical to maintain or operate. As related to GHG emissions, the U.S. Congress, environmental advocacy groups, other organizations and some state and federal agencies are focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that federal legislation and/or EPA regulation, and possibly additional state legislation and/or regulation, may pass resulting in the imposition of limitations on GHG emissions from fossil fuel-fired electric generating units. In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” If GHGs become regulated pollutants under the CAA, the Companies will be required to obtain permits for GHG emissions from new and modified facilities and amend operating permits for major sources of GHG emissions. Until these actions occur, and the EPA establishes guidance for GHG permitting, including Best Available Control Technology, it is not possible to determine the impact on Dominion’s and Virginia Power’s facilities that emit GHGs. However, such limits could make certain of the Companies’ electric generating units uneconomical to operate in the long term, unless there are significant advancements in the commercial availability and cost of carbon capture and storage technology. There are also potential impacts on Dominion’s natural gas businesses as federal GHG legislation may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission

regulations including regions where Dominion has operations. For example, Massachusetts has implemented regulations requiring reductions in CO₂ emissions and the Regional Greenhouse Gas Initiative, a cap and trade program covering CO₂ emissions from power plants in the Northeast, which affects several of Dominion’s facilities. In addition, a number of bills have been introduced in Congress that would require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted. Compliance with these GHG emission reduction requirements may require committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with expected GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology and associated regulations, and the selected compliance alternatives. As a result, Dominion and Virginia Power cannot estimate the effect of any such legislation on their results of operations, financial condition or their customers.

The base rates of Virginia Power are subject to regulatory review. As a result of the Regulation Act, in 2009, the Virginia Commission commenced its review of the base rates of Virginia Power under a modified cost-of-service model. Such rates will be set based on analyses of Virginia Power’s costs and capital structure, as reviewed and approved in regulatory proceedings. Under the Regulation Act, the Virginia Commission may, in a proceeding initiated in 2009, reduce rates or order a credit to customers if Virginia Power is deemed to be earning more than 50 basis points above an ROE level to be established by the Virginia Commission in that proceeding. After the initial rate case, the Virginia Commission will review the base rates of Virginia Power biennially and may order a credit to customers if it is deemed to have earned an ROE more than 50 basis points above an ROE level established by the Virginia Commission and may reduce rates if Virginia Power is found to have had earnings in excess of the established ROE level during two consecutive biennial review periods.

The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission operations and Dominion’s gas transmission operations is based primarily on rates approved by FERC. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.

Virginia Power’s wholesale charges for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter trued-up as appropriate to reflect actual costs allocated to Virginia Power by PJM. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia

Power’s wholesale revenue requirement is no longer just and reasonable.

Similarly, various rates and charges assessed by Dominion’s gas transmission businesses are subject to review by FERC. Dominion is required to file a general base rate review for the FERC-jurisdictional services of Cove Point, effective not later than July 31, 2011. At that time, Cove Point’s cost of service will be reviewed by the FERC, with rates set based on analyses of the Company’s costs and capital structure. The FERC-jurisdictional rates for DTI are the subject of a 2005 FERC-approved settlement. That settlement established a rate moratorium that continues in effect through June 30, 2010.

Energy conservation could negatively impact Dominion’s and Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of Dominion’s merchant generation, E&P assets and other unregulated business activities could be adversely impacted. In Virginia Power’s regulated operations, conservation could negatively impact its results depending on the regulatory treatment of the associated impacts. Should Virginia Power be required to invest 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. Dominion and Virginia Power are unable to determine what impact, if any, conservation will have on their financial condition or results of operations.

Dominion’s merchant power business is operating in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to purchase and sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.

In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise hedge its output, then these changes in market prices could adversely affect its financial results.

In addition, Dominion purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion’s financial results.

Lastly, Dominion is exposed to credit risks of its counterparties and the risk that one or more counterparties may fail to perform under their obligations to make payments. Defaults by suppliers or other counterparties may adversely affect Dominion’s financial results.

Dominion’s merchant power business may be negatively affected by possible FERC actions that could weaken competition in the wholesale markets or affect pricing rules in the RTO markets. Dominion’s merchant generation stations operating in PJM, MISO and ISO-NE sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these merchant generation stations to take advantage of market price opportunities, but also exposes them to market risk. Properly functioning competitive wholesale markets in PJM, MISO and ISO-NE depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize PJM, MISO and ISO-NE to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or Dominion’s authority to sell power at market-based rates could adversely impact the future results of its merchant power business.

Dominion’s and Virginia Power’s operations could be affected by terrorist activities and catastrophic events that could result from terrorism. In the event that their generating facilities or other infrastructure assets are subject to potential terrorist activities, such activities could significantly impair their operations and result in a decrease in revenues and additional costs to repair and insure their assets, which could have a material adverse effect on their business. The effects of potential terrorist activities could also include the risk of a significant decline in the U.S. economy, and the decreased availability and increased cost of insurance coverage, any of which could negatively impact the Companies’ results of operations and financial condition.

Dominion and Virginia Power have incurred increased capital and operating expenses and may incur further costs for enhanced security in response to such risks.

There are risks associated with the operation of nuclear facilities. Dominion and Virginia Power operate nuclear facilities that are subject to risks, including their 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 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. Decommissioning trusts and external insurance coverage are maintained to mitigate the financial exposure to these risks. However, it is possible that decommissioning costs could exceed the amount in the 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. Dominion and Virginia Power use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts primarily in the natural gas market for trading purposes. The Companies 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 contract. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, Dominion uses derivatives primarily to hedge its merchant generation and gas and oil production. The use of such derivatives to hedge future electric and gas sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where they have hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations.

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 Dominion’s results of operations.

Dominion’s and Virginia Power’s 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 their control and could adversely affect their results of operations and future growth.

For additional information concerning derivatives and commodity-based trading contracts, see Market Risk Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 8 to the Consolidated Financial Statements.

Dominion’s E&P business is affected by factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of Dominion’s assets. Factors that may affect Dominion’s financial results include, but are not limited to: damage to or suspension of operations caused by weather, fire, explosion or other events at Dominion’s or third-party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, Dominion’s ability to acquire additional land positions in competitive lease areas, drilling cost pressures, operational risks that could disrupt production, drilling rig availability and geological and other uncertainties inherent in the estimate of gas and oil reserves.

Declines in natural gas and oil prices could adversely affect Dominion’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues from the production of proved gas and oil reserves using trailing twelve month average natural gas and oil prices (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated and they may not be able to achieve the intended benefits of any such project, if completed. Several plant construction and expansion projects have been announced and additional projects may be considered in the future. Management anticipates that they will be required to seek additional financing in the future to fund current and future plant construction and expansion projects and may not be able to secure such financing on favorable terms. In addition, projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of their counterparties or vendors, or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the projects may not meet expectations. Additionally, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Further, Dominion and Virginia Power may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect their ability to realize the anticipated benefits from the plant construction and expansion projects.

An inability to access financial markets could affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets, longer-term capital markets and banks as significant sources of funding and liquidity for capital expenditures, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities primarily associated with Dominion’s merchant generation and gas and oil production. Management believes that the Companies will maintain sufficient access to these financial markets based upon their current credit ratings and market reputation. However, certain disruptions outside of Dominion’s and Virginia Power’s control may increase their cost of borrowing or restrict their ability to access one or more financial markets. Such disruptions could include delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, changes to their credit ratings or the failure of financial institutions on which they rely. Restrictions on the Companies’ ability to access financial markets may affect their ability to execute their business plans as scheduled.

Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which then could require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit plans. Dominion has significant obligations in these areas and holds significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates. A

decline in the market value of the assets may increase the funding requirements of the obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under Dominion’s pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension benefit plans. If the decommissioning trust funds and benefit plan assets are not successfully managed, Dominion’s results of operations and financial condition could be negatively affected.

Changing rating agency requirements could negatively affect Dominion’s and Virginia Power’s growth and business strategy. As of February 1, 2010, Dominion’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa2, stable outlook, by Moody’s; and BBB+, stable outlook, by Fitch. As of February 1, 2010, Virginia Power’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa1, positive outlook, by Moody’s; and A-, stable outlook, by Fitch. In order to maintain current credit ratings in light of existing or future requirements, Dominion and Virginia Power may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in Dominion’s credit ratings or the credit ratings of Virginia Power by Standard & Poor’s, Moody’s or Fitch could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominion to post additional collateral in connection with some of its price risk management activities.

Potential changes in accounting practices may adversely affect Dominion’s and Virginia Power’s financial results. Dominion and Virginia Power cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or their operations specifically. New accounting standards could be issued that could change the way they record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect 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 Dominion’s and Virginia Power’s operations. Dominion’s and Virginia Power’s business strategy is dependent on their 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 their business and future operating results.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

As of December 31, 2009, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power shares its

principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties.

Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.

Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2009; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens.

In 2007, Dominion sold its non-Appalachian E&P operations, whose historical results are included in the Corporate and Other segment. Dominion’s remaining Appalachian E&P operations, which are included in the Dominion Energy segment, do not qualify as significant gas and oil producing activities for 2009 or 2008. As a result, the following information only details Dominion’s gas and oil operations for 2007.

COMPANY-OWNED PROVED GAS AND OIL RESERVES

Estimated net quantities of proved gas and oil reserves were as follows:

bbl = barrel

Certain of Dominion’s subsidiaries file Form EIA-23 with the DOE which reports gross proved reserves, including the working interest shares of other owners, for properties operated by such subsidiaries. The proved reserves reported in the previous table represent Dominion’s share of proved reserves for all properties, based on its ownership interest in each property. For properties Dominion operates, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Dominion-owned proved reserves reported in the previous table, does not exceed five percent. Estimated proved reserves as of December 31, 2007 are based upon studies for each of Dominion’s properties prepared by its staff engineers and audited by Ryder Scott Company, L.P., an engineering firm registered by the Texas Board of Professional Engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.

QUANTITIES OF GAS AND OIL PRODUCED

Quantities of gas and oil produced follow:

bbl = barrel

The average realized price per mcf of gas with hedging results (including transfers to other Dominion operations at market prices) during 2007 was $5.99 and the average realized prices without hedging results per mcf of gas produced was $6.63. The average realized prices for oil with hedging results during 2007 was $37.78 per barrel and the average realized price without hedging results was $50.08 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during 2007 was $1.39.

NET WELLS DRILLED IN THE CALENDAR YEAR

The number of net wells completed follows:

POWER GENERATION

Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. The Companies supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2009, Dominion Generation’s total utility and merchant generating capacity was 27,507 MW.

Item 3. Legal Proceedings

From time to time, Dominion and Virginia Power are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by them, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies are involved in various legal proceedings. Dominion and Virginia Power believe that the ultimate resolution of these proceedings will not have a material adverse effect on their financial position, liquidity or results of operations.

See Regulation in Item 1. Business, Future Issues and Other Matters in Item 7. MD&A, and Notes 14 and 23 to the Consolidated Financial Statements for additional information on various environmental, rate matters and other regulatory proceedings to which Dominion and Virginia Power are parties.

In December 2006 and January 2007, Dominion submitted self-disclosure notifications to EPA Region 8 regarding three E&P facilities in Utah that potentially violated CAA permitting requirements. In July 2007, a third party purchased Dominion’s E&P assets in Utah, including these facilities. In September 2008, Dominion received a draft Consent Decree related to the potential CAA infractions, which imposes obligations on Dominion’s subsidiary, DEPI and the purchaser, including payment of a civil penalty to the U.S. Department of Justice in the amount of $250,000. In November 2009, the U.S. District Court, District of Utah, Northern Division entered the final Consent Decree. Per Dominion’s asset purchase agreement, the third-party purchaser paid the civil penalty as required by the Consent Decree.

In February 2009, DCP and its contractor Sheehan Pipeline Construction Company received notice from Maryland’s Attorney General’s Office that the Maryland Department of the Environment (MDE) had referred to them, for enforcement, alleged violations of state wetlands, water pollution, and sediment pollution laws during construction of a pipeline associated with the Cove Point expansion project in Maryland. This served notice that the MDE would be seeking civil penalties for some of the alleged violations. In May 2009, Dominion received a letter from the MDE detailing all alleged violations and their maximum penalty liabilities. In December 2009, the MDE entered into a consent order with Dominion and Sheehan dismissing its claims. Per the consent order, Dominion and Sheehan denied the MDE’s allegations, and agreed to pay $175,000 to the MDE and restore a pond. Of that penalty, Sheehan and its subcontractor agreed to pay $119,000; Dominion agreed to pay $56,000 and restore the pond.

In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at Dominion’s State Line and Kincaid power stations. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April, Dominion received a Notice and Finding of Violations from the EPA claiming new source review violations, new source performance standards violations, and Title V permit program violations pursuant to the CAA and the respective State Implementation Plans. Dominion is currently evaluating the impact of the Notice and cannot predict the outcome of this matter.

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

None.