Form 10-K

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Dominion Resources, Inc. Yes x No ¨ Virginia Electric and Power Company Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Dominion Resources, Inc. Yes ¨ No x Virginia Electric and Power Company Yes ¨ No x

The aggregate market value of Dominion Resources, Inc. common stock held by non-affiliates of Dominion was approximately $22.3 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of the registrant’s most recently completed second fiscal quarter. Dominion is the sole holder of Virginia Electric and Power Company common stock. As of January 31, 2011, Dominion had 580,849,359 shares of common stock outstanding and Virginia Power had 274,723 shares of common stock outstanding.

(a) Portions of Dominion’s 2011 Proxy Statement are incorporated by reference in Part III.

This combined Form 10-K represents separate filings by Dominion Resources, Inc. and Virginia Electric and Power Company. Information contained herein relating to an individual registrant is filed by that registrant on its own behalf. Virginia Power makes no representations as to the information relating to Dominion’s other operations.

The following abbreviations or acronyms used in this Form 10-K are defined below:

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 27,615 MW of generating capacity, 6,100 miles of electric transmission lines, 56,800 miles of electric distribution lines, 11,000 miles of natural gas transmission, gathering and storage pipeline and 21,800 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less. Dominion also owns the nation’s largest underground natural gas storage system, operates approximately 947 bcf of storage capacity and serves retail energy customers in 14 states.

Dominion is focused on expanding its investment in regulated electric generation, transmission and distribution and regulated natural gas transmission and distribution 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.

In 2010, Dominion announced plans to invest more than $10 billion over the next five years to expand and improve its regulated electric and natural gas businesses. A substantial portion of this investment will be essential to meet the anticipated increase in electricity demand in its service territory. Other drivers for the capital investment program include the need to construct infrastructure to handle the expected increase in natural gas production from the Marcellus Shale formation and upgrades to its gas distribution and electric transmission and distribution network. Dominion also announced that it may invest up to an additional $2 billion in its electric generating fleet to meet potential new environmental requirements.

Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations. 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 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.

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

EMPLOYEES

As of December 31, 2010, Dominion had approximately 15,800 full-time employees, of which approximately 5,900 employees are subject to collective bargaining agreements. As of December 31, 2010, Virginia Power had approximately 6,800 full-time employees, of which approximately 3,000 employees are subject to collective bargaining agreements. See Note 23 for discussion of the Companies’ workforce reduction program.

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.

DISPOSITIONS

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

SALE OF E&P PROPERTIES

In 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations, including its rights to associated Marcellus acreage, to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. See Note 4 to the Consolidated Financial Statements for additional information.

In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion.

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 the non-Appalachian E&P operations are included in the Corporate and Other segment. The historical results of the Appalachian E&P operations are included in the Dominion Energy segment.

SALE OF PEOPLES

In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The historical results of these operations are included in the Corporate and Other segment and presented in discontinued operations. See Note 4 to the Consolidated Financial Statements for additional information.

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 received a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. The overriding royalty interest was transferred to CONSOL as part of the sale of substantially all of Dominion’s Appalachian E&P operations in 2010.

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. The results of these operations were presented in discontinued operations.

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 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.

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.

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, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations, which are discussed in Notes 4 and 25 to the Consolidated Financial Statements, respectively. 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.

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:


Primary Operating Segment	Description of Operations	Dominion		Virginia Power
DVP	Regulated electric distribution		X		X
	Regulated electric transmission		X		X
	Nonregulated retail energy marketing (electric and gas)		X
Dominion Generation	Regulated electric fleet		X		X
	Merchant electric fleet		X
Dominion Energy	Gas transmission and storage		X
	Gas distribution and storage		X
	LNG import and storage		X
	Producer services		X

For additional financial information on operating segments, including revenues from external customers, see Note 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, which serve residential, commercial, industrial and governmental customers in Virginia and 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 changes in rates, 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 and customer service have improved. SAIDI, excluding major storm events, has also steadily improved. The three-year average SAIDI has improved from 135 minutes at the end of 2005 to 114 minutes at the end of 2010. Likewise, ASA has also shown significant improvement. The three-year average ASA has improved from 73 seconds at the end of 2005 to 42 seconds at the end of 2010. 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. As electric distribution moves forward, safety, electric service reliability and customer service will remain key focal areas.

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.

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, NERC compliance 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 continued to experience customer growth during the past few years. The retail business requires limited capital investment and currently employs approximately 160 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.

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. Pursuant to this legislation, the Virginia Commission initiated a review of Virginia Power’s base rates in 2009. A discussion of Virginia Power’s settlement of this case with the Virginia Commission is contained in Electric Regulation in Virginia under Regulation.

PROPERTIES

Virginia Power has approximately 6,100 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Power’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. Virginia Power is involved in two of the major construction projects authorized in 2006, which are designed to improve the reliability of service to customers and the region—Meadow Brook-to-Loudoun and Carson-to-Suffolk.

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 rights-of-way. 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. On appeal by the ECCP, the Pennsylvania Commonwealth Court affirmed in May 2010 the Pennsylvania Commission’s approval and subsequently denied a request for reargument by the ECCP in June 2010. The Meadow

Brook-to-Loudoun line is expected to cost approximately $255 million and 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.

As part of subsequent annual PJM RTEP processes, PJM authorized additional electric transmission upgrade projects including Hayes-to-Yorktown in December 2008 and Mt. Storm-to-Doubs in December 2010. In June 2010, the Virginia Commission authorized the construction of the Hayes-to-Yorktown line along the proposed eight-mile route utilizing existing easements and property previously acquired for the transmission line right-of-way. In accordance with the Virginia Commission’s approval, approximately 4.2 miles of the Hayes-to-Yorktown line will be constructed overhead and approximately 3.8 miles will be installed underground in order to cross under the York River. The Hayes-to-Yorktown line is expected to cost approximately $63 million and, subject to receipt of all regulatory approvals, is expected to be completed by June 2012.

After more than 44 years of operation, portions of the 99-mile Mt. Storm-to-Doubs line and certain associated facilities are approaching the end of their expected service lives and require replacement with new facilities to maintain reliable service. Virginia Power owns and has been designated by PJM to rebuild the 96 miles of the line in West Virginia and Virginia, and The Potomac Edison Company owns and has been designated by PJM to rebuild the remaining three miles of the line in Maryland. Subject to applicable state and federal regulatory approvals, Virginia Power’s portion of the rebuild project is expected to cost approximately $300 million and is expected to be completed by June 2015.

In addition, Virginia Power’s electric distribution network includes approximately 56,800 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain rights-of-way that have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

SOURCES OF 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. DVP’s 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. Revenue is based primarily on rates established by state regulatory authorities and state law. Approximately 80% of revenue comes from serving Virginia jurisdictional customers. Rates for the Virginia jurisdiction are set using a modified cost-of-service rate model, subject to base rate caps that were in effect through December 31, 2008. The cost of fuel and purchased power is generally collected through fuel cost-recovery mechanisms established by regulators and does not materially impact net income. 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. See Regulation—State Regulations for additional information, including a discussion of Virginia Power’s 2009 base rate case settlement with the Virginia Commission.

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. 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, primarily natural gas, 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 of its merchant fleet by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements. However, earnings have been adversely impacted due to a sustained decline in commodity prices. 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

Virginia Power’s generation operations are not subject to significant competition as only a limited number of its Virginia jurisdictional electric utility customers have retail choice. See Regulation—State Regulations—Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation Operating Segment—Dominion

Unlike Dominion Generation’s regulated generation fleet, its merchant generation fleet is dependent on its ability to operate in a competitive environment and does not have a predetermined rate structure that allows for a rate of return on its capital investments. Competition for the merchant fleet is impacted by electricity and fuel prices, new market entrants, construction by others of generating assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. These competitive factors may negatively impact the merchant fleet’s ability to profit from the sale of electricity and related products and services.

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 price competition during the term of these contracts. Following expiration of these contracts, earnings could be adversely impacted if prevailing prices for energy, capacity and ancillary services are lower than the levels currently received under these contracts.

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 existing 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 its utility service area, Virginia Power will need additional generation capacity over the next decade. 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 anticipated growing demand in its core market in Virginia. Significant projects under construction or development include:

Bear Garden, which, once operational, will generate about 580 MW. This intermediate, combined-cycle, natural gas-fired power station and transmission interconnection line is estimated to cost $619 million, excluding financing costs. Construction is approximately 94% complete as of January 2011, with commercial operations expected to commence in the second quarter of 2011.

The Virginia City Hybrid Energy Center located in Wise County, Virginia, which once operational, will generate about 585 MW. The baseload facility is estimated to cost $1.8 billion, excluding financing costs. Construction is approximately 79% complete as of January 2011, and commercial operations are expected to commence in the summer of 2012.

A power station development project in Warren County, Virginia, intended to be developed as an intermediate, combined-cycle, natural gas-fired power station. In December 2010, the Virginia Department of Environmental Quality approved an air permit to construct the project. Subject to the receipt of additional regulatory approvals, the project is expected to generate more than 1,300 MW of electricity. If the project is approved, construction would begin in 2012, with commercial operations expected to commence by late 2014 or early 2015.

In addition to the projects above, 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 May 2010, Virginia Power announced its decision to replace the reactor design previously selected for the potential third nuclear unit with the US-APWR technology.

In June 2010, Virginia Power and ODEC amended the COL application to reflect the selection of the US-APWR technology. In January 2011, Virginia Power and the DOE terminated their cooperative agreement to share equally the cost of developing a COL. The agreement references the technology previously selected by Virginia Power. DOE funding is not available under the agreement for activities related to the US-APWR technology. During the third and fourth quarters of 2010, Virginia Power filed several applications for environmental permits that would be needed to support future construction and operation of a third nuclear unit at North Anna.

Virginia Power has not yet committed to building a new nuclear unit at North Anna. In October 2010, Virginia Power announced its decision to slow the development of the potential third reactor. Virginia Power will continue to pursue the COL, along with engineering and preliminary site development work, and will reassess a construction schedule prior to the issuance of the COL currently anticipated in 2013. In December 2010, Virginia Power and MNES reached an agreement regarding pre-construction, engineering, design and planning work in preparation for a possible new unit at North Anna. In February 2011, ODEC informed Virginia Power of its intent to no longer participate in the development of the new unit at North Anna. Virginia Power and ODEC are currently working together to finalize the terms and conditions of such withdrawal.

If Virginia Power decides to build the new unit, it must first receive a COL from the NRC, the approval of the Virginia Commission and certain environmental permits and other approvals. The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the ASLB of the NRC permitted BREDL to intervene in the proceeding. All of BREDL’s previous contentions in this proceeding have been dismissed. In October 2010, BREDL submitted two new contentions that it seeks to litigate that Virginia Power has opposed. No other persons sought to intervene in the proceeding. Absent additional admitted contentions, the mandatory NRC hearing will be uncontested with respect to other issues.

In April 2008, Virginia Power announced a joint effort with BP to evaluate wind energy projects in Virginia. In December 2010, Virginia Power and BP terminated their joint development agreement for wind energy projects. As a result of the termination, Virginia Power has acquired a sole development interest in several wind energy development projects in Virginia. Virginia Power paid BP approximately $1.5 million to acquire BP’s interest in property jointly owned in Tazewell County, Virginia.

Dominion Generation Operating Segment—Dominion

Dominion is a 50% owner with BP of the first phase of Fowler Ridge. Phase one has generating capacity of 300 MW and is in full commercial operation. In December 2009, Dominion closed on an agreement with BP to split the 350 MW of development assets associated with the second phase of Fowler Ridge, with Dominion retaining 150 MW of these development assets. In December 2010, Dominion reached an agreement to sell its 150 MW share of the development assets of the second phase to BP. Closing is subject to the approvals of FERC and the Indiana Utility Regulatory Commission, which are expected by the second quarter of 2011. Dominion will receive approximately $6 million of proceeds from the sale.

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:


	2010 Source			2009 Source			2008 Source
Coal⁽¹⁾		31	%		33	%		33	%
Purchased power, net		29			25			29
Nuclear⁽²⁾		28			32			31
Natural gas		10			9			6
Other⁽³⁾		2			1			1
Total		100	%		100	%		100	%

(1)

Excludes ODEC’s 50.0% ownership interest in the Clover power station. The average cost of coal for 2010 Virginia in-system generation was $36.25 per MWh.

(2)

Excludes ODEC’s 11.6% ownership interest in North Anna.

(3)

Includes oil, hydro and biomass.

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 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 Surry and North Anna 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 NRC’s 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 2010 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 other 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. Any funds remaining in Kewaunee’s trust after decommissioning is completed are required to be refunded to Wisconsin ratepayers.

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 NRC’s 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 $4.6 billion in 2010 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. In February 2011, the NRC renewed the operating license, extending Kewaunee’s operation an additional 20 years through 2033. Full decommissioning of Kewaunee is expected during the period 2033 to 2065.

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

NRC

license

expiration

year

Most
recent
cost
estimate
(2010
dollars)

Funds in
trusts at
December 31,
2010

2010
contributions
to trusts

(dollars in millions)

Surry

Unit 1

2032

541

373

1.1

Unit 2

2033

562

368

1.2

North Anna

Unit 1⁽¹⁾

2038

550

298

0.8

Unit 2⁽¹⁾

2040

564

280

0.8

Total (Virginia Power)

2,217

1,319

3.9

Millstone

Unit 1⁽²⁾

n/a

424

317

—

Unit 2

2035

651

385

—

Unit 3⁽³⁾

2045

680

374

—

Kewaunee

—

Unit 1⁽⁴⁾

2013

658

502

—

Total (Dominion)

4,630

2,897

3.9

(1)

North Anna is jointly owned by Virginia Power (88.4%) and ODEC (11.6%). However, Virginia Power is responsible for 89.26% of the decommissioning obligation. Amounts reflect 100% of the decommissioning cost for both of North Anna’s units.

(2)

Unit 1 ceased operations in 1998, before Dominion’s acquisition of Millstone.

(3)

Millstone Unit 3 is jointly owned by Dominion, Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation, who hold a 6.53% undivided interest in Unit 3. Amounts reflect 100% of the decommissioning cost for Millstone Unit 3.

(4)

Kewaunee Unit 1 original license expiration year is 2013, however, the cost estimate is based on the license renewal expiration year of 2033.

Dominion Energy

Dominion Energy includes Dominion’s regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities and regulated LNG 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. 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 are dependent on weather, changes in commodity prices and the economy.

In October 2008, East Ohio implemented a rate case settlement which began a transition to a straight-fixed-variable rate design. Under this rate design, 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, East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.

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

Earnings from Dominion Energy’s 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 21,800 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 11,000 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 262,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 947 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 Cove Point. Dominion Energy has about 123 compressor stations with more than 768,000 installed compressor horsepower.

In July 2008, East Ohio launched the PIR program to replace approximately 20% of its 21,000-mile pipeline system. The project, which is anticipated to cost approximately $2.6 billion, primarily involves the replacement of East Ohio’s bare steel, cast iron, wrought iron and copper pipe over a 25-year period. As part of this program, East Ohio will assume ownership of curb-to-meter service lines and will be responsible for line repairs or replacement. In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of the PIR program.

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 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 March 2010, Dominion commenced construction of the Cove Point Pier Reinforcement Project. The $50 million project is intended to upgrade, expand and modify the existing pier at the Cove Point terminal to accommodate the next generation of LNG vessels (up to 267,000 cubic meters) that are much larger than what can currently be accommodated (no larger than 148,000 cubic meters). The project commenced with the south berth being taken temporarily out of service to accommodate construction activities. In October 2010, Dominion requested and received FERC authorization to re-commence service from the south berth of the pier for vessels with cargo capacities of no greater than 148,000 cubic meters. When the south berth was returned to service, construction commenced on the north berth, which was taken out of service. In December 2010, Dominion

requested and received authorization to place the project in service on January 21, 2011.

DTI 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 DTI’s West Virginia system. Construction started in 2009 and is expected to be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.

DTI 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. DTI 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.

DTI has announced the proposed development of a gas pipeline project, known as the Appalachian Gateway Project. The project is expected to provide approximately 484,000 dekatherms per day of firm transportation services for new Appalachian gas supplies from the supply areas in the Appalachian Basin in West Virginia and southwestern Pennsylvania to an interconnection with Texas Eastern Transmission, LP at Oakford, Pennsylvania. Plans call for construction to start in 2011, with transportation services to begin by September 2012. An open season concluded in September 2008 and the project is fully subscribed under long-term binding agreements. In June 2010, DTI filed a certificate application with the FERC seeking approval for the Appalachian Gateway project. DTI estimates the cost of the Appalachian Gateway project to be approximately $634 million.

In June 2010, DTI entered into a 15-year firm transportation agreement with the gas subsidiary of CONSOL. The project, known as the Northeast Expansion Project, is expected to provide approximately 200,000 dekatherms per day of firm transportation services for CONSOL’s Marcellus Shale natural gas production from various receipt points in central and southwestern Pennsylvania to a nexus of market pipelines and storage facilities in Leidy, Pennsylvania. The $97 million project will involve the construction by DTI of new compression facilities at three existing compressor stations in central Pennsylvania, subject to the receipt of regulatory approval. In November 2010, DTI filed a certificate application with FERC seeking approval for the Northeast Expansion Project. If the project is approved, construction is expected to begin in March 2012, with a projected in-service date of November 2012.

In August 2010, DTI entered into a 10-year lease agreement with TGP for firm capacity to move Marcellus shale natural gas supplies from TGP’s 300 Line pipeline system in northern Pennsylvania to its 200 Line pipeline system in upstate New York. The $46 million project, known as the Ellisburg-to-Craigs Project, is expected to have capacity of approximately 150,000 dekatherms per day. Subject to the receipt of regulatory approvals, the project will involve the construction by DTI of additional compression facilities and a new measurement and regulating station at the

Craigs interconnect with TGP in New York. DTI filed a certificate application with FERC in November 2010. If the Ellisburg-to-Craigs Project is approved, construction is expected to begin in March 2012, with a planned in-service date of November 2012.

In January 2011, Dominion announced that DTI is developing a natural gas processing and fractionation facility near New Martinsville, West Virginia. Dominion reached an agreement with PPG Industries, Inc. to purchase 56 acres at the Natrium site where DTI plans to process natural gas and NGLs.

SOURCES OF ENERGY SUPPLY

Dominion Energy’s natural gas supply is obtained from various sources including purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers. 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.

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 East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipeline and storage business can also be weather sensitive. Commodity prices 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 certain 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 Peoples and certain DCI operations, which

are discussed in Notes 4 and 25 to the Consolidated Financial Statements, respectively. 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:

Compliance with applicable environmental laws, regulations and rules;

Conservation and load management;

Renewable generation development;

Other generation development to maintain fuel diversity, including clean coal, advanced nuclear energy, and natural gas; and

Improvements in other energy infrastructure.

See Global Climate Change under Regulation—Environmental Regulations in this item for examples of the Companies’ efforts to reduce their impact on the environment.

Environmental Compliance

Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules related to their operations. Additional information related to Dominion’s and Virginia Power’s environmental compliance obligations can be found in Note 23 to the Consolidated Financial Statements.

Conservation and Load Management

Conservation plays a significant role in meeting the growing demand for electricity. The Regulation Act provides incentives for energy conservation and sets a voluntary 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. Legislation in 2009 added definitions of peak-shaving and energy efficiency programs and allowed for a margin on operating expenses and revenue reductions related to energy efficiency programs. Virginia Power’s DSM programs provide the first steps toward achieving the voluntary ten percent energy conservation goal.

Virginia Power continues to assess smart grid technologies through a demonstration designed to indicate how these technologies may enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. The demonstration involves a limited deployment, within Virginia Power’s Virginia service territory, of smart meters that use digital technology to enable two-way communication between the meter and Virginia Power’s electric distribution system. Dependent upon the outcome of the demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is intended to help customers monitor and control their energy use. It is also expected to lead to more efficient

use of the power grid, which is expected to result in energy savings and lower environmental emissions.

Additionally, the conservation and load management plan includes the following DSM programs, which were approved by the Virginia Commission in March 2010:

Residential Lighting Program—an instant, in-store discount on the purchase of qualifying compact fluorescent lights;

Home Energy Improvement—energy audits and improvements for homes of low-income customers;

Smart Cooling Rewards—incentives for residential customers who voluntarily enroll to allow Virginia Power to cycle their air conditioners and heat pumps during periods of peak demand;

Commercial HVAC Upgrade Program—incentives for commercial customers to improve the energy efficiency of their heating and/or cooling units; and

Commercial Lighting Program—incentives for commercial customers to install energy-efficient lighting.

Virginia Power has also proposed a redesigned distributed generation program which was not approved in its original form by the Virginia Commission in 2010. Virginia Power plans to seek Virginia Commission approval of the redesigned distributed generation program and several other DSM programs in 2011.

In September 2010, Virginia Power filed with the North Carolina Commission an application for approval and cost recovery of the DSM programs listed above, as well as the redesigned distributed generation program. In February 2011, the North Carolina Commission approved the five DSM programs listed above. The North Carolina Commission will make a decision regarding the appropriate rate making treatment for the programs in a separate proceeding. Virginia Power expects to launch the five DSM programs within its North Carolina service territory in the second quarter of 2011, subject to cost recovery approval by the North Carolina Commission. Virginia Power’s request for approval of the redesigned distributed generation program remains pending before the North Carolina Commission.

Renewable Generation

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 RPS of 12.5% by 2021. In May 2010, the Virginia Commission approved Virginia Power’s participation in the state’s RPS program. As a participant, Virginia Power is permitted to seek recovery, through rate adjustment clauses, of costs of programs designed to meet RPS goals. Virginia Power plans to meet the respective RPS targets in Virginia and North Carolina by utilizing existing renewable facilities, as well as the Virginia City Hybrid Energy Center, which is expected to use at least 10% biomass. In addition, Virginia Power intends to purchase renewable energy certificates, as permitted by each RPS program, to meet any remaining annual requirement needs. Virginia Power continues to explore opportunities to develop new renewable facilities within its service territory, the energy attributes of which would qualify for inclusion in the RPS programs.

In June 2010, Virginia Power announced its plans to develop an integrated solar and battery storage demonstration project in

Halifax County, Virginia. The proposed facility is intended to manage, store, and optimize solar energy to regulate intermittency, enable peak shaving and increase grid reliability. In November 2010, the Virginia Tobacco Indemnification and Community Revitalization Commission approved a $5 million grant to help fund the proposed project. Other project participants are the Halifax County Industrial Development Authority, the University of Virginia and a battery storage manufacturer. Subject to approval by the Virginia Commission and final project development, the 4 MW facility is expected to be operational in 2013.

In addition, Dominion is a 50% owner of NedPower. Dominion’s share of this project produces 132 MW of renewable energy.

Dominion is also a 50% owner with BP of the first phase of Fowler Ridge, which has a generating capacity of 300 MW. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In December 2010, Dominion reached an agreement to sell its remaining share of the development assets of the second phase of Fowler Ridge to BP.

Other Generation Development

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 anticipated growth in demand in its 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. One component of the Powering Virginia program involves consideration of the extent to which Virginia Power can 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 are six generally recognized GHGs including CO₂, methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. The focus is on new generation because there is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store GHG emissions. Given that new generation units have useful lives of up to 55 years, Virginia Power will consider CO₂ and other GHG emissions when making these long-term decisions. See Dominion Generation—Properties for more information.

Improvements in Other Energy Infrastructure

In December 2010, Virginia Power announced its five-year investment plan, which includes spending approximately $4 billion to upgrade or add new transmission and distribution lines, substations and other facilities to meet growing electricity demand within its service territory and maintain reliability. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service, and are intended to address both continued population growth and increases in electricity consumption by the typical consumer. 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 Regulation—Environmental Regulations in this item for more information.

Virginia Power is taking measures to ensure that its electrical infrastructure can support the expected demand from electric vehicles, which have significantly lower carbon intensity than conventional vehicles. Virginia Power has partnered with Ford Motor Company to help prepare Virginia for the operation of electric vehicles, in a collaboration that involves consumer outreach, educational programs and the exchange of information on vehicle charging requirements.

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

Prior to the Regulation Act, which significantly changed electricity regulation in Virginia, Virginia Power’s Virginia jurisdictional base rates were to be capped at 1999 levels until December 31, 2010, at which time Virginia was to convert to retail competition for its electric supply service. The Regulation Act ended capped rates two years early, on December 31, 2008, at which time retail competition was made available only to individual retail customers with a demand of more than 5 MW and non-residential retail customers who obtain Virginia Commission approval to aggregate their load to reach the 5 MW threshold. Individual retail customers are also permitted to purchase renewable energy from competitive suppliers if their incumbent electric utility does not offer a 100% renewable energy tariff.

The Regulation Act also authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. The Regulation Act provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to nuclear generation, clean coal/carbon capture compatible generation and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating the 2009 Base Rate Review. In connection with the 2009 Base Rate Review, Virginia Power submitted base rate filings and accompanying schedules to the Virginia Commission during 2009. In February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission, which had the support of all of the interested parties, including the Staff of the Virginia Commission. Virginia Power’s fourth quarter 2009 results included a charge of $782 million ($477 million after-tax) representing its best estimate at the time of the probable outcome of the 2009 Base Rate Review. In March 2010, the Virginia Commission issued the Virginia Settlement Approval Order that concluded the 2009 Base Rate Review and resolved open issues relating to Virginia Power’s fuel factor and Rider T. An ROE issue relating to Riders R, S, C1 and C2 was also resolved.

The Virginia Settlement Approval Order included the following provisions:

Credits from 2008 Revenues

Credits to customers of $400 million from Virginia Power’s 2008 revenues to be applied against base rates and rider charges.

Base Rates

No change in Virginia Power’s base rates in existence prior to September 1, 2009 until December 1, 2013 (unless emergency rate relief is warranted by statute);

Refund increased revenues collected under the interim base rates since September 1, 2009; and

An ROE of 11.9% (inclusive of a performance incentive of 60 basis points) for use in the Virginia Commission’s assessment in the upcoming biennial rate review of Virginia Power’s earnings.

FTR Credits

Credits to customers of $129 million, inclusive of any carrying charge, relating to revenues from FTRs for the period July 1, 2007 through June 30, 2009.

Generation Riders R and S

An ROE of 12.3% (inclusive of a 100 basis point statutory enhancement) for the 2010 rate year.

Transmission Rider T

Waiver of recovery, effective January 1, 2011, of deferred RTO start-up and administrative costs in the amount of $197 million (including carrying charges) that were previously approved for recovery through Rider T.

DSM Riders C1 and C2

An ROE of 11.3% for the 2010 rate year.

Commencing in 2011, the Virginia Commission will conduct biennial reviews of Virginia Power’s base rates, terms and conditions. In the biennial review, as in the 2009 Base Rate Review, Virginia Power’s authorized ROE can be no lower than the average of that reported by not less than a majority of comparable utilities within the Southeastern U.S., with certain limitations as described in the Regulation Act. If Virginia Power’s earnings are

more than 50 basis points above the authorized level, such earnings will be shared with customers.

Virginia Power previously 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 Virginia Power’s retail customers by ten percent of what was consumed in 2006. In March 2010, the Virginia Commission approved the recovery of approximately $28 million for five of the DSM programs through initiation of Riders C1 and C2, effective May 1, 2010. With respect to the other six DSM programs for which approval was sought, the Virginia Commission made a finding that they were not in the public interest at that time, but allowed Virginia Power the opportunity for further evaluation of similar programs. In July 2010, Virginia Power submitted its annual update filing for Riders C1 and C2 with respect to the five approved DSM programs. The proposed revenue requirements for Riders C1 and C2 were approximately $6 million and $18 million, respectively, which together represent a decrease of approximately $5 million compared to the Riders C1 and C2 revenue requirements included in customer rates currently in effect. In February 2011, an evidentiary hearing was held by the Virginia Commission on Virginia Power’s update of Riders C1 and C2. The Virginia Commission is required to issue its order by March 30, 2011. Virginia Power plans to seek Virginia Commission approval for several DSM programs in 2011. See Environmental Strategy for a description of Virginia Power’s DSM programs.

In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in June 2010, Virginia Power filed annual updates for Riders R and S, respectively, with the Virginia Commission. Initially, Virginia Power proposed an approximately $86 million revenue requirement for Rider R for the April 1, 2011 to March 31, 2012 rate year. Due to the application of accelerated tax depreciation provisions in the Small Business Jobs Act of 2010, passed in September 2010, Virginia Power revised the requested revenue requirement for Rider R in November 2010 from $86 million to $78 million. The adjusted $78 million revenue requirement represents an increase of approximately $14 million over the revenue requirement associated with the Rider R customer rates currently in effect. The proposed Rider S revenue requirement, effective April 1, 2011, for the rate year ending March 31, 2012 is approximately $200 million, which represents an increase of $46 million over the revenue requirement associated with the Rider S customer rates currently in effect. The ROE included in both rider filings is 12.3%, which is consistent with the terms of the Virginia Settlement Approval Order. In July 2010, the Virginia Commission issued orders with respect to Riders R and S, which adopted a placeholder ROE of 11.3% (not including the 100 basis point statutory enhancement) for use until the ROE is determined in the context of Virginia Power’s upcoming biennial review. Evidentiary hearings were held by the Virginia Commission on Riders R and S in December and November 2010, respectively.

The Virginia Commission is required to issue its orders in these proceedings by March 30, 2011.

With respect to Virginia Power’s costs of transmission service, in June 2010, the Virginia Commission approved Virginia Power’s annual update to Rider T which was effective September 1, 2010, reflecting the revenue requirement of approximately $338 million recommended by the Virginia Commission Staff and agreed to by Virginia Power. The $338 million revenue requirement reflects an increase of approximately $118 million over the previous revenue requirement.

In April 2010, Virginia Power filed its Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $82 million for the period July 1, 2010 through June 30, 2011. The proposed fuel factor went into effect on July 1, 2010 on an interim basis. An evidentiary hearing on Virginia Power’s application was held in September 2010, and in October 2010, the Virginia Commission issued its final order approving the reduction in Virginia Power’s fuel factor as proposed in its application.

If the Virginia Commission’s future rate decisions, including actions relating to Virginia Power’s upcoming biennial review and 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

Virginia Power’s North Carolina base rates have been subject to a five-year base rate moratorium, effective as of April 2005. Fuel rates continued to be subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.

In February 2010, in preparation for the end of the five-year base rate moratorium, Virginia Power filed an application to increase its base rates and adjust its fuel rates. Virginia Power’s application included a proposal to recover proportionately more of its purchased power energy costs through fuel rates, which are adjusted annually, instead of being recovered in base rates. In August 2010, Virginia Power filed its annual application for a change in its fuel rates, which updated the fuel application of February 2010 to reflect a proposed decrease of approximately $28 million when compared to current fuel rates. Also in August 2010, Virginia Power updated its base rate application to seek a $27 million increase, instead of $29 million as originally proposed.

In September 2010, all parties to the base rate and fuel case except one, which did not oppose the settlement, filed an Agreement and Stipulation of Settlement and requested approval from the North Carolina Commission. In December 2010, the North Carolina Commission issued the North Carolina Settlement Approval Order. The North Carolina Settlement Approval Order authorizes an increase in base revenues of approximately $8 million and a one-year decrease in combined fuel revenues of approximately $32 million when compared to revenues produced from current rates. In addition, the North Carolina Settlement Approval Order permits the recovery through fuel rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generators subject to economic dispatch that do not provide actual cost data. The

North Carolina Settlement Approval Order authorizes an ROE of 10.7% and a capital structure composed of 49% long-term debt and 51% common equity. Virginia Power does not agree that the foregoing ROE represents its anticipated or actual cost of equity or capital structure, but accepted the resulting revenue requirement for the purpose of a global settlement of disputed issues in the proceedings. The new base and fuel rates became effective on January 1, 2011.

GAS

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

Status of Competitive Retail Gas Services

Both of the states in which Dominion has gas distribution operations have 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 offers retail choice to residential and commercial customers. At December 31, 2010, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, 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, 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 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, East Ohio buys natural gas under the Standard Service Offer program for customers not eligible to participate in the Energy Choice program and places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills. Subject to the Ohio Commission’s approval, East Ohio may eventually exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. East Ohio continues 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.

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 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 base rate revenue increase and an 8.49% allowed rate of return on rate base for East Ohio, which were reflected in revised base rates commencing December 22, 2008.

In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of East Ohio’s 25-year PIR program to replace approximately 20% of its 21,000-mile pipeline system. In August 2009, East Ohio filed an application with the Ohio Commission seeking approval of the first annual adjustment to the PIR cost recovery charge approved as part of East Ohio’s 2008 base rate case. The application included a revenue requirement of approximately $16 million, which was subsequently reduced to approximately $13 million by an order issued by the Ohio Commission in December 2009. East Ohio opposed the order, however, its application for rehearing of the decision was denied. In March 2010, East Ohio filed a notice of appeal with the Supreme Court of Ohio alleging that the Ohio Commission’s order in the matter was unlawful, unjust and unreasonable. Dominion cannot predict the outcome of the appeal, however, it is not expected to have a material effect on results of operations.

In August 2010, East Ohio filed its second annual application to adjust the cost recovery charge associated with its PIR program for actual costs and a return on investments made through June 30, 2010. The application reflected a revenue requirement of approximately $28 million. In November 2010, the Ohio Commission approved a settlement agreement filed by East Ohio and the Staff of the Ohio Commission reflecting a revenue requirement of approximately $27 million. Other interested parties to the case neither supported nor objected to the settlement agreement.

Under the Ohio PIPP program, eligible customers can receive energy assistance based on their ability to pay their bill. The difference between the customer’s total bill and the PIPP plan payment amount is deferred and collected under the PIPP rider in accordance with the rules of the Ohio Commission. Due to increased participation in the program and increases in gas costs in the period since the previous rider rate went into effect, unrecovered costs increased. Accordingly, in March 2010, the Ohio Commission approved a 12-month recovery of approximately $259 million of uncollected receivables associated with the PIPP program, comprised of accumulated PIPP arrearages of $163 million and projected arrearages of $96 million for the 12 months that the PIPP rider rate will be in effect. The PIPP

rider rate went into effect in April 2010. The Ohio Commission directed East Ohio to file an application, with arrearages calculated on a calendar year basis, to update its PIPP rider within one year of implementation of the new PIPP rider rate and annually thereafter.

In November 2010, rule changes adopted by the Ohio Commission to the PIPP program became effective. The rule changes established a new program, PIPP Plus, which replaced PIPP. The PIPP Plus program reduces the customer’s monthly payments from 10% to 6% of household income and provides for forgiveness credits to the customer’s balance when required payments are received in full by the due date. Such credits may result in the elimination of the customer’s arrearage balance over 24 months.

East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in PIPP Plus. The UEX Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio’s actual write-offs of uncollectable amounts. In 2010, East Ohio deferred approximately $55 million of bad debt expense for recovery through the UEX Rider.

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. In June 2010, the West Virginia Commission authorized an additional base rate increase of less than $1 million to correct a miscalculation of rates attached to the November 2009 order.

Federal Regulations

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.

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 the issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand, the impact of any PJM rate design changes on the Companies’ results of operations is not expected to be material.

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.

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%, effective as of January 1, 2008. The formula rate is designed to recover the expected revenue requirement for each calendar year and is updated based on actual costs. The FERC-approved formula method, which is based on projected costs, allows Virginia Power to earn a 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 revenue requirement 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 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 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. Although Virginia Power cannot predict the outcome of the rehearing, it is not expected to have a material effect on results of operations.

lish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power’s rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. While Virginia Power cannot predict the outcome of this proceeding, it is not expected to have a material effect on results of operations.

In May 2008, the RPM Buyers filed a complaint with 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. In November 2009, the Court transferred the appeal to the Court of Appeals for the District of Columbia Circuit. In February 2011, the Court of Appeals denied the petition for review, concluding that FERC had adequately explained why the rates were just and reasonable.

EPACT included provisions to create an ERO. The ERO 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 ERO and also issued an initial order approving many reliability standards that went into effect in 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 plan and operate their facilities in compliance with approved NERC reliability requirements. Dominion and Virginia Power employees participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. Dominion and Virginia Power anticipate incurring additional compliance expenditures over the next several years as a result of the implementation of new cyber security programs as well as efforts to ensure appropriate facility ratings for Virginia Power’s transmission lines. In October 2010, NERC issued an industry alert identifying possible discrepancies between the design and actual field conditions of transmission facilities as a potential reliability issue. The alert recommends that entities review their current facilities rating methodology to verify that the methodology is based on actual field conditions, rather than solely on design documents, and to take corrective action if necessary. Virginia Power is evaluating its transmission facilities for any discrepancies between design and actual field conditions. In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cyber security assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

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, Cove Point 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, 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 this 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 DTI, its customers and interested state commissions. The settlement, which became effective July 1, 2005, revised DTI’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. DTI remains subject to the terms of the tariff rates established pursuant to the settlement.

In December 2007, DTI and the IOGA entered into a settlement agreement on DTI’s gathering and processing rates, which DTI and IOGA agreed in May 2010 to extend through December 31, 2014. DTI, at its option, may elect to extend the agreement for an additional year through December 31, 2015. The settlement extension maintains 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. DTI will file the negotiated rates associated with the agreement extension with FERC in December 2011.

Dominion is required to file a general base rate review for the FERC-jurisdictional services of Cove Point, effective no later than July 1, 2011. At that time, Cove Point’s cost of service will be reviewed by the FERC, with rates set based on analyses of Cove Point’s costs and capital structure.

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 appli-

cable 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, which information is incorporated herein by reference. 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 has developed a comprehensive GHG inventory for calendar year 2009. For Dominion Generation, Dominion’s and Virginia Power’s direct CO₂ equivalent emissions, based on equity share (ownership), were approximately 54 million metric tonnes and 33 million metric tonnes, respectively, in 2009. 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 Cove Point) direct CO₂ equivalent emissions were approximately 2.5 million metric tonnes and East Ohio’s direct CO₂ equivalent emissions were approximately 1.4 million metric tonnes. While the Companies do not have final 2010 emissions data, they do not expect a significant variance in emissions from 2009 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 U.S. Electric Code of Federal Regulation. 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 EPA’s Mandatory Reporting of Greenhouse Gases 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 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.

Climate Change Legislation and Regulation

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

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. Below are some of the Companies’ efforts that have or are expected to reduce the Companies’ carbon emissions or intensity:

In 2003, Virginia Power retired two oil-fired units at its Possum Point power station, replacing them with a new 559 MW combined-cycle natural gas unit. Virginia Power also converted two coal-fired units to cleaner burning natural gas.

Since 2000, Dominion has added over 2,600 MW of non-emitting nuclear generation and over 3,500 MW of new lower-emitting natural gas-fired generation including nearly 1,600 MW at Virginia Power (excluding Possum Point), to its generation mix.

Virginia Power added 83 MW of renewable biomass.

Dominion has over 800 MW of wind energy in operation or development.

In June 2010, Virginia Power announced its plans to develop an integrated solar and battery storage demonstration project in Halifax County, Virginia.

Virginia Power is completing construction of the 580 MW combined-cycle natural gas-fired Bear Garden generating facility.

Virginia Power has announced its plans to develop the Warren County power station development project, which is designed to be a 3-on-1, combined-cycle, natural gas-fired power station expected to generate more than 1,300 MW of electricity. In connection with the air permit process for the Warren County project, Virginia Power reached an agreement with the National Park Service to permanently retire the North Branch power station, a 74 MW coal fired plant located in West Virginia, once the Warren County power station begins commercial operations.

Virginia Power and ODEC have received an Early Site Permit from the NRC for the possible addition of approximately 1,500 MW of nuclear generation in Virginia. Virginia Power has not yet committed to building a new nuclear unit.

In May 2010, Virginia Power launched five new DSM programs within the Virginia service territory and has sought the approval of the North Carolina commission to launch six new

DSM programs in North Carolina in 2011, subject to required regulatory approvals.

Virginia Power has initiated a demonstration of smart grid technologies, which are designed to help reduce the electric energy consumption of Virginia Power’s retail customers and therefore reduce generation requirements.

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 10% biomass for fuel and is 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 2009, 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 16% and 5%, 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 Dominion’s and Virginia Powers’ 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 Millstone 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. In May 2010, the stay was lifted, and the government’s initial brief in the appeal was filed in June 2010. The issues raised by the government on appeal pertain to the damages awarded to Dominion for Millstone. The government did not take issue with the damages awarded to Virginia Power for Surry or North Anna. As a result, Virginia Power recognized a receivable in the amount of $174 million, largely offset against property, plant and equipment and regulatory assets and liabilities, representing certain spent nuclear fuel-related costs incurred through June 30, 2010. Briefing on the appeal was concluded in September 2010 and oral argument took place before the Federal Circuit in January 2011. Payment of any damages will not occur until the appeal process has been resolved.

A lawsuit was also filed for Kewaunee. In August 2010, Dominion and the federal government reached a settlement resolving Dominion’s claims for damages incurred at Kewaunee through December 31, 2008. The approximately $21 million settlement payment was received in September 2010.

The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Virginia Power and Kewaunee continue to recognize receivables for certain spent nuclear fuel-related costs that they believe are probable of recovery from 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 results of 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 result in substantial expense.

Dominion and Virginia Power could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of generation facilities and bulk electric transmission systems, including Dominion and Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. Compliance with the mandatory reliability standards may subject the Companies to higher operating costs and may result in increased capital expenditures. If either Dominion or Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to remediation costs, as well as sanctions, including substantial monetary penalties.

Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant. The costs of compliance with future environmental laws, including laws and regulations designed to address global climate change, air quality, coal combustion by-products, cooling water and other matters could make certain of the Companies’ generation facilities uneconomical to maintain or operate. 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, environmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, the Companies 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.

Existing environmental laws and regulations may be revised and/or new laws may be adopted or become applicable to Domin-

ion or Virginia Power. The EPA is expected to issue additional regulations with respect to air quality under the CAA, including revised NAAQS, a replacement of the CAIR relating to NO_X and SO₂emissions, and a MACT rule for coal and oil-fired electric generation plants that will likely address numerous HAPs, including mercury. Risks relating to potential regulation of GHG emissions are discussed below. Dominion and Virginia Power also expect additional federal water and waste regulations, including regulations concerning cooling water intake structures and coal combustion by-product handling and disposal practices.

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. However, such expenditures, if excessive, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.

If additional federal and/or state requirements are imposed on energy companies mandating limitations on GHG emissions, such requirements may result in compliance costs that alone or in combination could make some of Dominion’s or Virginia Power’s electric generation units uneconomical to maintain or operate. 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 additional EPA regulation, and possibly additional state legislation and/or regulation, may pass resulting in the imposition of additional limitations on GHG emissions from fossil fuel-fired electric generating units.

There are also potential impacts on Dominion’s natural gas businesses as federal GHG legislation and regulations 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 through RGGI, a cap and trade program covering CO₂ emissions from power plants in the Northeast, which affects several of Dominion’s facilities.

Compliance with GHG emission reduction requirements may require increasing the energy efficiency of equipment at facilities, 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 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, the Companies cannot estimate the effect of any such legislation on their results of operations, financial condition or their customers. However, such expenditures, if excessive, could make the Companies’ generation facilities uneconomical to operate, result in the impairment of assets, or otherwise adversely affect Dominion’s or Virginia Power’s results of operations, financial performance or liquidity.

The base rates and rider 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. That review culminated in a final order in March 2010, in which the Commission ordered that Virginia Power’s base rates be frozen at their pre-September 1, 2009 levels until December 1, 2013. In 2011, however, the Virginia Commission will commence biennial reviews of the rates and terms and conditions of Virginia Power and, in that first biennial review, may order a credit to customers for a portion of earnings more than 50 basis points above the authorized ROE.

The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission and distribution operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission operations and Dominion’s gas transmission and distribution operations is based primarily on rates approved by federal and state regulatory agencies. 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 adjusted 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 no 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 Cove Point’s costs and capital structure.

Dominion’s gas distribution businesses are subject to state regulatory review in the jurisdictions in which they operate.

Risks arising from the reliability of electric generation, transmission and distribution equipment could result in lost revenues and increased expenses, including higher maintenance costs. Operation of the Companies’ generation, transmission and distribution facilities involves risk, including, the risk of potential breakdown or failure of equipment or processes, due to aging infrastructure, fuel supply or transportation disruptions, accidents, labor disputes or work stoppages by employees, acts of terrorism or sabotage, construction delays or cost overruns, shortages of or delays in obtaining equipment, material and labor, operational restrictions

resulting from environmental limitations and governmental interventions, and performance below expected levels. In addition, weather-related incidents and other natural disasters can disrupt generation, transmission and distribution facilities. Because Virginia Power’s transmission facilities are interconnected with those of third parties, the operation of its facilities could be adversely affected by unexpected or uncontrollable events occurring on the systems of such third parties.

Operation of the Companies’ generation facilities below expected capacity levels could result in lost revenues and increased expenses, including higher maintenance costs. Unplanned outages of generating units and extensions of scheduled outages due to mechanical failures or other problems occur from time to time and are an inherent risk of the Companies’ business. Unplanned outages typically increase the Companies’ operation and maintenance expenses and may reduce their revenues as a result of selling less energy or may require the Companies to incur significant costs as a result of operating higher cost units or obtaining replacement energy and capacity from third parties in the open market to satisfy forward energy and capacity obligations. Moreover, if the Companies are unable to perform their contractual obligations, penalties or liability for damages could result.

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.

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.

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 elec-

tricity markets regulated by FERC. The wholesale markets allow these merchant generation stations to take advantage of market price opportunities, but also expose 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.

War, acts and threats of terrorism, natural disaster and other significant events could adversely affect Dominion’s and Virginia Power’s operations. We cannot predict the impact that any future terrorist attacks may have on the energy industry in general, or on our business in particular. Any retaliatory military strikes or sustained military campaign may affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets. In addition, infrastructure facilities, such as electric generation, electric and gas transmission and distribution facilities could be direct targets of, or indirect casualties of, an act of terror. Furthermore, the physical or cyber security compromise of our facilities, could adversely affect our ability to manage these facilities effectively. Instability in financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors could result in a significant decline in the U.S. economy, and the increased cost of insurance coverage, any of which could negatively impact the Companies’ results of operations and financial condition.

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, including 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.

The use of derivatives to hedge future 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 it has 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 between the location and/or 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 the Companies’ control and could adversely affect their results of operations and future growth.

The Dodd-Frank Act, which was enacted into law in July 2010, includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Final rules for the over-the-counter derivatives-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and capital and margin requirements, will be established through the CFTC’s rulemaking process, which is required to be completed by July 2011. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs for their derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivatives provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities.

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.

Exposure to counterparty performance may adversely affect the Companies’ financial results of operations. Dominion and Virginia Power are exposed to credit risks of their counterparties and the risk that one or more counterparties may fail or delay the performance of their contractual obligations, including but not limited to payment for services. Such defaults by customers, suppliers or other third parties may adversely affect the Companies’ financial results.

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. Additionally, technological advances driven by federal laws mandating new levels of energy efficiency in end-use electric devices, including lighting and electric heat pumps, could lead to declines in per capita energy consumption. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of the Companies’ business activities could be adversely impacted.

An inability to access financial markets could adversely affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets and longer-term capital markets 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. Deterioration in the Companies’ creditworthiness, as evaluated by credit rating agencies or otherwise, or market reputation, or general financial market disruptions outside of Dominion’s and Virginia Power’s control could increase their cost of borrowing or restrict their ability to access one or more financial markets. Further market disruptions could stem from delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, or the failure of financial institutions on which the Companies rely. Increased costs and restrictions on the Companies’ ability to access financial markets may be severe enough to 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 and other postretirement benefit plans. If the decommissioning trust funds and benefit plan assets are negatively impacted by market fluctuations, 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. In order to maintain appropriate credit ratings to obtain needed credit at a reasonable cost in light of existing or future rating agency 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 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, 2010, 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, which information is incorporated herein by reference.

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

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, 2010, Dominion Generation’s total utility and merchant generating capacity was 27,615 MW.

The following tables list Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2010:

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, which information is incorporated herein by reference 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 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 State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, 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. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement authority under the CAA. Dominion cannot predict the outcome of this matter. However, an adverse resolution could have a material effect on future results of operations and/or cash flows.

In May 2010, 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 Brayton Point and Salem Harbor. Dominion submitted its response to the request in November 2010 and cannot predict the outcome of this matter.

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Dominion’s common stock is listed on the NYSE. At January 31, 2011, there were approximately 144,000 record holders of Dominion’s common stock. The number of record holders is comprised of individual shareholder accounts maintained on Dominion’s transfer agent records and includes accounts with shares held in (1) certificate form, (2) book-entry in the Direct Registration System and (3) book-entry under Dominion’s direct stock purchase and dividend reinvestment plan. Discussions of the restrictions on Dominion’s payment of dividends required by this Item are contained in Dividend Restrictions in Item 7. MD&A and Notes 18 and 21 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2010 and 2009. Quarterly information concerning stock prices and dividends is disclosed in Note 28 to the Consolidated Financial Statements, which information is incorporated herein by reference.

The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2010.

There is no established public trading market for Virginia Power’s common stock, all of which is owned by Dominion. Restrictions on Virginia Power’s payment of dividends are discussed in Dividend Restrictions in MD&A and Note 21 to the Consolidated Financial Statements. Virginia Power paid quarterly cash dividends on its common stock as follows:

2010 results include a $1.4 billion after-tax net income benefit from the sale of substantially all of Dominion’s Appalachian E&P operations, net of charges related to the divestiture and a $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, as discussed in Notes 4 and 23 to the Consolidated Financial Statements, respectively. Also in 2010, Dominion recorded $127 million of after-tax impairment charges at certain merchant generation facilities, as discussed in Note 7 to the Consolidated Financial Statements. The loss from discontinued operations in 2010 includes a $140 million after-tax loss on the sale of Peoples.

2009 results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements. Also in 2009, Dominion recorded a $281 million after-tax ceiling test impairment charge related to the carrying value of its E&P properties.

2008 results include $109 million of after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts. In addition, income from discontinued operations in 2008 includes a $120 million after-tax benefit due to the reversal of deferred tax liabilities associated with the sale of Peoples.

2007 results include a $1.5 billion after-tax benefit from the disposition of Dominion’s non-Appalachian E&P operations and a $252 million after-tax impairment charge associated with the sale of Dresden. Also in 2007, Dominion recorded a $137 million after-tax charge resulting from the termination of the long-term power sales agreement associated with State Line. In addition, the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge.

2006 reflects the net impact of the discontinued operations of Peoples sold in 2010, Canadian E&P operations sold in June 2007 and the Peaker facilities sold in March 2007. Discontinued operations for Peoples includes a $119 million after-tax charge primarily due to the recognition of deferred tax liabilities, as well as a $114 million after-tax charge resulting from the write-off of certain regulatory assets, both in connection with the sale. Discontinued operations for the Peaker facilities includes a $164 million after-tax impairment charge to reduce the facilities’ carrying amounts to their estimated fair values less cost to sell.

2010 results include a $123 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program, discussed in Note 23 to the Consolidated Financial Statements.

2009 results include a $427 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings discussed in Note 14 to the Consolidated Financial Statements.

2007 results reflect the reapplication of accounting guidance for cost-based rate regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

MD&A discusses Dominion’s and Virginia Power’s results of operations and general financial condition. MD&A should be read in conjunction with Item 1. Business and the Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

CONTENTS OF MD&A

MD&A consists of the following information:

Forward-Looking Statements

Accounting Matters

Dominion

Results of Operations

Segment Results of Operations

Virginia Power

Results of Operations

Segment Results of Operations

Liquidity and Capital Resources

Future Issues and Other Matters

FORWARD-LOOKING STATEMENTS

This report contains statements concerning Dominion’s and Virginia Power’s expectations, plans, objectives, future financial performance and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. In most cases, the reader can identify these forward-looking statements by such words as “anticipate,” “estimate,” “forecast,” “expect,” “believe,” “should,” “could,” “plan,” “may,” “continue,” “target” or other similar words.

Dominion and Virginia Power make forward-looking statements with full knowledge that risks and uncertainties exist that may cause actual results to differ materially from predicted results. Factors that may cause actual results to differ are often presented with the forward-looking statements themselves. Additionally, other factors may cause actual results to differ materially from those indicated in any forward-looking statement. These factors include but are not limited to:

Unusual weather conditions and their effect on energy sales to customers and energy commodity prices;

Extreme weather events, including hurricanes, high winds and severe storms, that can cause outages and property damage to facilities;

Federal, state and local legislative and regulatory developments;

Changes to federal, state and local environmental laws and regulations, including those related to climate change, the tightening of emission or discharge limits for GHGs and other emissions, more extensive permitting requirements and the regulation of additional substances;

Cost of environmental compliance, including those costs related to climate change;

Risks associated with the operation of nuclear facilities;

Unplanned outages of the Companies’ facilities;

Fluctuations in energy-related commodity prices and the effect these could have on Dominion’s earnings and Dominion’s and Virginia Power’s liquidity position and the underlying value of their assets;

Counterparty credit and performance risk;

Capital market conditions, including the availability of credit and the ability to obtain financing on reasonable terms;

Risks associated with Virginia Power’s membership and participation in PJM related to obligations created by the default of other participants;

Price risk due to investments held in nuclear decommissioning trusts by Dominion and Virginia Power and in benefit plan trusts by Dominion;

Fluctuations in interest rates;

Changes in federal and state tax laws and regulations;

Changes in rating agency requirements or credit ratings and their effect on availability and cost of capital;

Changes in financial or regulatory accounting principles or policies imposed by governing bodies;

Employee workforce factors including collective bargaining agreements and labor negotiations with union employees;

The risks of operating businesses in regulated industries that are subject to changing regulatory structures;

Receipt of approvals for and timing of closing dates for acquisitions and divestitures;

Changes in rules for RTOs and ISOs in which Dominion and Virginia Power participate, including changes in rate designs and new and evolving capacity models;

Political and economic conditions, including the threat of domestic terrorism, inflation and deflation;

Industrial, commercial and residential growth or decline in the Companies’ service areas and changes in customer growth or usage patterns, including as a result of energy conservation programs;

Additional competition in electric markets in which Dominion’s merchant generation facilities operate;

Changes in technology, particularly with respect to new, developing or alternative sources of generation and smart grid technologies;

Changes to regulated electric rates collected by Virginia Power and regulated gas distribution, transportation and storage rates, including LNG storage, collected by Dominion;

Timing and receipt of regulatory approvals necessary for planned construction or expansion projects;

The inability to complete planned construction projects within the terms and time frames initially anticipated; and

Adverse outcomes in litigation matters.

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

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

ACCOUNTING FOR REGULATED OPERATIONS

The accounting for Virginia Power’s regulated electric and Dominion’s regulated gas operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs are deferred as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

The Companies evaluate whether or not recovery of their regulatory assets through future rates is probable and make various assumptions in their analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of a regulatory asset is determined to be less than probable, it will be written off in the period such assessment is made. The Companies currently believe the recovery of their regulatory assets is probable. See Notes 13 and 14 to the Consolidated Financial Statements.

ASSET RETIREMENT OBLIGATIONS

Dominion and Virginia Power recognize liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, the Companies estimate the fair value of their AROs using present value techniques, in which they make various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. AROs currently reported in the Consolidated Balance Sheets were measured during a period of historically low interest rates. The impact on measurements of new AROs or remeasurements of existing AROs, using different cost escalation rates in the future, may be significant. When the Companies revise any assumptions used to calculate the fair value of existing AROs, they adjust the carrying amount of both the ARO liability and the related long-lived asset. The Companies accrete the ARO liability to reflect the passage of time.

In 2010, 2009 and 2008, Dominion recognized $85 million, $89 million and $94 million, respectively, of accretion, and expects to recognize $81 million in 2011. In 2010, 2009 and 2008, Virginia Power recognized $35 million, $35 million and $38 million, respectively, of accretion, and expects to recognize $37 million in 2011. Virginia Power records accretion and depreciation associated with utility nuclear decommissioning AROs as an adjustment to its regulatory liability for nuclear decommissioning.

A significant portion of the Companies’ AROs relates to the future decommissioning of Dominion’s merchant and Virginia

Power’s utility nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2010, Dominion’s nuclear decommissioning AROs totaled $1.4 billion, representing approximately 87% of its total AROs. At December 31, 2010, Virginia Power’s nuclear decommissioning AROs totaled $620 million, representing approximately 92% of its total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with the Companies’ nuclear decommissioning obligations.

The Companies obtain from third-party specialists periodic site-specific base year cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for their nuclear plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. In addition, the Companies’ cost estimates include cost escalation rates that are applied to the base year costs. The selection of these cost escalation rates is dependent on subjective factors which are considered to be a critical assumption.

The Companies determine cost escalation rates, which represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities, for each nuclear facility. As a result of the updated decommissioning cost studies and applicable escalation rates obtained in 2009, Dominion recorded a decrease of $309 million in the nuclear decommissioning AROs of its units, including a $103 million ($62 million after-tax) reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service. Virginia Power recorded a decrease of $119 million in the nuclear decommissioning AROs for its units.

INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows and adjustments to tax-related assets and liabilities could be material.

Given the uncertainty and judgment involved in the determination and filing of income taxes, there are standards for recognition and measurement in financial statements of positions taken or expected to be taken by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. At December 31, 2010, Dominion had $307 million and Virginia Power had $117 million of unrecognized tax benefits. For a substantial amount of these unrecognized tax benefits, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility.

Deferred income tax assets and liabilities are recorded representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power evaluate quar-

terly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. The Companies establish a valuation allowance when it is more-likely-than-not that all or a portion of a deferred tax asset will not be realized. At December 31, 2010, Dominion had established $68 million of valuation allowances and Virginia Power had no valuation allowances.

ACCOUNTING FOR DERIVATIVE CONTRACTS AND OTHER INSTRUMENTS AT FAIR VALUE

Dominion and Virginia Power use derivative contracts such as futures, swaps, forwards, options and FTRs to manage commodity and financial market risks of their business operations. Derivative contracts, with certain exceptions, are reported in the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in Dominion’s and Virginia Power’s nuclear decommissioning and Dominion’s rabbi and benefit plan trust funds are also subject to fair value accounting. See Notes 7 and 22 to the Consolidated Financial Statements for further information on these fair value measurements.

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, management seeks indicative price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, the Companies consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases the Companies must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis, that reflect their market assumptions.

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value.

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2010, Dominion reported $3.1 billion of goodwill in its Consolidated Balance Sheet. A significant portion resulted from the acquisition of the former CNG in 2000.

In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount. The 2010, 2009 and 2008 annual tests and any interim tests did not result in the recognition of any goodwill impairment.

In general, Dominion estimates the fair value of its reporting units by using a combination of discounted cash flows and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving

peer group companies. For Dominion’s Appalachian E&P operations, Peoples and Hope and certain DCI operations, negotiated sales prices were used as fair value for the tests conducted in 2010, 2009 and 2008. Fair value estimates are dependent on subjective factors such as Dominion’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in Dominion’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present. See Note 12 to the Consolidated Financial Statements for additional information.

USE OF ESTIMATES IN LONG-LIVED ASSET IMPAIRMENT TESTING

Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying if circumstances indicate an impairment may exist, identifying and grouping affected assets, and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including probability weighting such cash flows to reflect expectations about possible variations in their amounts or timing and the selection of an appropriate discount rate. Although cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors which may change over time, such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed. See Note 7 to the Consolidated Financial Statements for a discussion of impairments related to certain long-lived assets.

EMPLOYEE BENEFIT PLANS

Dominion sponsors noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

obligations and the anticipated rate of increase in healthcare costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between Dominion’s assumptions and actual experience, is generally recognized in the Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

The expected long-term rates of return on plan assets, discount rates and healthcare cost trend rates are critical assumptions. Dominion determines the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

Historical return analysis to determine expected future risk premiums, asset volatilities and correlations;

Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices;

Expected inflation and risk-free interest rate assumptions; and

Investment allocation of plan assets. The strategic target asset allocation for Dominion’s pension funds is 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments, such as private equity investments.

Strategic investment policies are established for each of Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target.

Dominion develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Dominion calculated its pension cost using an expected long-term rate of return on plan assets assumption of 8.50% for 2010, 2009 and 2008. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2010, 2009 and 2008. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets.

Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans. The discount rates used to calculate pension cost and other postretirement benefit cost were 6.60% in 2010 and 2009, compared to 6.60% and 6.50%, respectively, in 2008. Dominion selected a discount rate of 5.90% for determining its December 31, 2010 projected pension and other postretirement benefit obligations.

Dominion establishes the healthcare cost trend rate assumption based on analyses of various factors including the specific provisions of its medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s healthcare cost trend rate assumption as of December 31, 2010 is 7.0% and is expected to gradually decrease to 4.60% by 2060 and continue at that rate for years thereafter.

The following table illustrates the effect on cost of changing the critical actuarial assumptions previously discussed, while holding all other assumptions constant:


				Increase in Net Periodic Cost
	Change in Actuarial Assumption			Pension Benefits		Other Postretirement Benefits
(millions, except percentages)
Discount rate		(0.25	)%	$	13	$	5
Long-term rate of return on plan assets		(0.25	)%		13		3
Healthcare cost trend rate		1.00	%		N/A		23

In addition to the effects on cost, at December 31, 2010, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $138 million and its accumulated postretirement benefit obligation by $52 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $217 million. See Note 22 to the Consolidated Financial Statements for additional information.

REVENUE RECOGNITION—UNBILLED REVENUE

Virginia Power recognizes and records revenues when energy is delivered to the customer. The determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, the amounts of electric energy delivered to customers, but not yet billed, is estimated and recorded as unbilled revenue. This estimate is reversed in the following month and actual revenue is recorded based on meter readings. Virginia Power’s customer receivables included $397 million and $355 million of accrued unbilled revenue at December 31, 2010 and 2009, respectively.

The calculation of unbilled revenues is complex and includes numerous estimates and assumptions including historical usage, applicable customer rates, weather factors and total daily electric generation supplied, adjusted for line losses. Changes in generation patterns, customer usage patterns and other factors, which are the basis for the estimates of unbilled revenues, could have a significant effect on the calculation and therefore on Virginia Power’s results of operations and financial condition.

Other

ACCOUNTING STANDARDS AND POLICIES

During 2009 and 2008, Dominion and Virginia Power were required to adopt several new accounting standards, which are discussed in Note 3 to the Consolidated Financial Statements.

DOMINION

RESULTS OF OPERATIONS

Presented below is a summary of Dominion’s consolidated results:


Year Ended December 31,	2010		$ Change		2009		$ Change			2008
(millions, except EPS)
Net Income attributable to Dominion	$	2,808	$	1,521	$	1,287	$	(547	)	$	1,834
Diluted EPS		4.76		2.59		2.17		(0.99	)		3.16

Overview

2010 VS. 2009

Net income attributable to Dominion increased by 118%. Favorable drivers include a gain on the sale of Dominion’s Appalachian E&P operations, lower ceiling test impairment charges related to these properties, the absence of a charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings and the impact of favorable weather on electric utility operations. Unfavorable drivers include charges related to a workforce reduction program, a loss on the sale of Peoples, lower margins from merchant generation operations and impairment charges related to certain merchant generation facilities.

2009 VS. 2008

Net income attributable to Dominion decreased by 30%. Unfavorable drivers include an impairment charge related to the carrying value of Dominion’s E&P properties due to declines in gas and oil prices during the first quarter of 2009 and a charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings. Favorable drivers include higher margins in Dominion’s merchant generation operations and a higher contribution from Dominion’s gas transmission operations due to the completion of the Cove Point expansion project.

Analysis of Consolidated Operations

Presented below are selected amounts related to Dominion’s results of operations:


Year Ended) December 31,	2010			$ Change			2009		$ Change			2008
(millions)
Operating Revenue	$	15,197		$	399		$	14,798	$	(1,097	)	$	15,895
Electric fuel and other energy-related purchases		4,150			(135	)		4,285		262			4,023
Purchased electric capacity		453			42			411		—			411
Purchased gas		2,050			(150	)		2,200		(966	)		3,166
Net Revenue		8,544			642			7,902		(393	)		8,295
Other operations and maintenance		3,724			12			3,712		428			3,284
Depreciation, depletion and amortization		1,055			(83	)		1,138		104			1,034
Other taxes		532			49			483		(10	)		493
Gain on sale of Appalachian E&P operations		2,467			2,467			—		—			—
Other income (loss)		169			(25	)		194		236			(42	)
Interest and related charges		832			(57	)		889		60			829
Income tax expense		2,057			1,461			596		(357	)		953
Income (loss) from discontinued operations		(155	)		(181	)		26		(164	)		190

An analysis of Dominion’s results of operations follows:

2010 VS. 2009

Net Revenue increased 8%, primarily reflecting:

A $1.1 billion increase from electric utility operations, primarily reflecting:

The absence of a charge for the settlement of Virginia Power’s 2009 base rate case proceedings ($570 million);

The impact of Riders C1 and C2, R, S and T ($279 million);

An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and

An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand; partially offset by

A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million);

A $98 million increase from regulated natural gas distribution operations primarily reflecting increased rider revenue associated with the recovery of bad debt expense ($60 million) and an increase in base rates ($40 million); and

A $46 million increase related to natural gas transmission operations largely due to the completion of the Cove Point expansion project.

These increases were partially offset by:

A $356 million decrease from merchant generation operations due to a decrease at certain nuclear generating facilities ($237 million) primarily due to lower realized prices, a decline in margins at certain fossil generation facilities ($70 million)

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

primarily due to an increase in fuel prices and the expiration of certain requirements-based power sales contracts in December 2009 ($49 million);

A $222 million decrease reflecting the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010; and

A $40 million decrease in producer services primarily related to unfavorable price changes on economic hedging positions and lower physical margins, all associated with natural gas aggregation, marketing and trading activities.

Other operations and maintenance increased $12 million primarily reflecting:

A $240 million net increase in salaries, wages and benefits primarily related to a workforce reduction program. As a result of the program, Dominion expects to avoid future annualized operations and maintenance expenses of approximately $100 million that would have otherwise been incurred;

Impairment charges related to certain merchant generating facilities ($194 million);

A $103 million increase due to the absence of a benefit in 2009 from a downward revision in the nuclear decommissioning ARO for a unit that is no longer in service;

A $56 million increase in bad debt expense at regulated natural gas distribution operations, primarily related to low income assistance programs ($60 million). These expenses are recovered through rates and do not impact net income; and

A $42 million increase in certain electric transmission-related expenditures.

These increases were partially offset by:

A $434 million decrease in ceiling test impairment charges related to the carrying value of Dominion’s E&P properties;

The absence of a $142 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings; and

A $48 million decrease in outage costs due to a decrease in scheduled outage days primarily at certain merchant generation facilities.

DD&A decreased 7%, primarily due to the sale of Dominion’s Appalachian E&P operations ($45 million) and lower amortization due to decreased cost of emissions allowances consumed ($37 million).

Other taxes increased 10%, primarily due to additional property tax from increased investments and higher rates ($16 million), an increase in gross receipts tax due to new non-regulated retail energy customers ($14 million) and higher payroll taxes associated with a workforce reduction program ($12 million).

Gain on sale of Appalachian E&P operations reflects a gain on the sale of these operations, as described in Note 4 to the Consolidated Financial Statements.

Other income decreased 13%, primarily reflecting an increase in charitable contributions ($46 million) and a decrease in interest income ($15 million); partially offset by the absence of an impairment loss on an equity method investment ($30 million) and higher realized gains (including investment income) on nuclear decommissioning trust funds ($12 million).

Interest and related charges decreased 6%, primarily due to a benefit resulting from the net effect of the discontinuance of hedge accounting for certain interest rate hedges and subsequent changes in fair value of these interest rate derivatives ($73 million), partially offset by an increase in interest expense associated with the June 2009 hybrid issuance ($26 million).

Income tax expense increased $1.5 billion, primarily reflecting higher federal and state taxes largely due to the gain on the sale of Dominion’s Appalachian E&P business.

Loss from discontinued operations primarily reflects a loss on the sale of Peoples.

2009 VS. 2008

Net Revenue decreased 5%, primarily reflecting:

A $614 million decrease in net revenue from electric utility operations primarily due to a charge for the settlement of Virginia Power’s 2009 base rate case proceedings;

An $86 million decrease in sales of gas production from E&P operations primarily reflecting the expiration of VPP royalty interests; and

A $21 million decrease in net gas revenue from retail energy marketing operations primarily due to lower prices ($39 million), partially offset by higher volumes ($18 million).

These decreases were partially offset by:

A $161 million increase from merchant generation operations, primarily reflecting lower fuel expenses due to the impact of lower commodity prices ($190 million) and higher sales volumes primarily from fewer scheduled nuclear refueling outages and higher demand for natural gas generation ($143 million), partially offset by lower sales prices ($79 million) and increased fuel consumption ($93 million) at certain fossil generation facilities;

A $158 million increase related to gas transmission operations largely due to the completion of the Cove Point expansion project; and

A $70 million increase in net electric revenue from retail energy marketing operations primarily attributable to higher volumes ($36 million) and the acquisition of a retail energy marketing business in September 2008 ($34 million).

Other operations and maintenance expense increased 13%, primarily reflecting the combined effects of:

A $455 million ceiling test impairment charge related to the carrying value of E&P properties due to declines in natural gas and oil prices;

A $142 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings; and

A $74 million increase in salaries, wages and benefits largely due to higher pension and other postretirement benefit costs.

These increases were partially offset by:

A $103 million downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service;

The absence of a $59 million charge related to the impairment of a DCI investment sold in 2008; and

A $29 million decrease largely due to the deferral of electric transmission-related expenditures collectible under certain rate adjustment clauses.

DD&A increased 10%, principally due to higher depreciation from property additions ($100 million) and higher amortization due to increased consumption of emissions allowances ($37 million), partially offset by decreased DD&A reflecting lower gas and oil production ($19 million) and a decrease in DD&A rates ($28 million) at Dominion’s E&P properties.

Other income (loss) increased $236 million primarily due to the impact of net realized gains (including investment income) on merchant nuclear decommissioning trust funds in 2009 as compared to net realized losses (net of investment income) in 2008.

Interest and related charges increased 7%, primarily due to the impact of additional borrowings ($34 million) and the absence of a $23 million benefit related to the redemption of Virginia Power’s Callable and Puttable Enhanced Securities in 2008.

Income tax expense decreased by 37%, primarily reflecting lower pre-tax income in 2009.

Outlook

In order to deliver favorable returns to investors, Dominion’s strategy is to continue focusing on its regulated businesses while maintaining upside potential in well-positioned nonregulated businesses. The goals of this strategy are to provide earnings per share growth, a growing dividend and a stable credit profile. Dominion’s 2010 results were positively impacted by the gain on the sale of substantially all of its Appalachian E&P operations. In 2011, Dominion’s operating businesses will likely experience a decrease in net income on a per share basis as compared to 2010. Dominion’s anticipated 2011 results reflect the following significant factors:

Lower realized margins from its merchant generation operations due to lower commodity prices and an increase in planned outages at certain nuclear and fossil facilities;

A return to normal weather in its electric utility operations; and

The absence of earnings from Appalachian E&P operations sold in April 2010; partially offset by

Growth in electric sales resulting from the recovering economy;

A benefit from rate adjustment clause revenue associated with Bear Garden and Virginia City Hybrid Energy Center;

A reduction in certain operations and maintenance expenses resulting largely from the implementation of cost-containment measures, including the workforce reduction program discussed in Note 23 to the Consolidated Financial Statements; and

Lower outage costs at certain electric utility generating facilities.

Dominion also expects the bonus depreciation provisions of the tax legislation recently enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable by $1.2 billion to $2.1 billion during 2011 through 2013. The acceleration of these tax deductions is expected to reduce the domestic production activities income tax deduction through 2012 and will also increase deferred taxes, thereby reducing rate base for regulated operations. However, Dominion plans to partially mitigate the earnings per share impact of these items by using the cash tax savings to

repurchase common stock in 2011 and reduce the amount of debt that would have otherwise been issued over the next three years. In addition, Dominion does not plan any market issuances of common stock in 2011 or 2012.

Dominion expects its operating businesses to provide five percent to six percent growth in net income on a per share basis in 2012 as compared to 2011 primarily due to its assumptions regarding construction and operation of new infrastructure in its utility operations, fewer merchant outages and an anticipated rise in commodity prices and energy demand.

SEGMENT RESULTS OF OPERATIONS

Segment results include the impact of intersegment revenues and expenses, which may result in intersegment profit or loss. Presented below is a summary of contributions by Dominion’s operating segments to net income attributable to Dominion:


Year Ended December 31,	2010				2009						2008
	Net Income attribut- able to Dominion		Diluted EPS		Net Income (loss) attribut- able to Dominion			Diluted EPS			Net Income (loss) attribut- able to Dominion			Diluted EPS
(millions, except EPS)
DVP	$	448	$	0.76	$	384		$	0.65		$	380		$	0.65
Dominion Generation		1,291		2.19		1,281			2.16			1,227			2.11
Dominion Energy		475		0.80		517			0.87			470			0.81
Primary operating segments		2,214		3.75		2,182			3.68			2,077			3.57
Corporate and Other		594		1.01		(895	)		(1.51	)		(243	)		(0.41	)
Consolidated	$	2,808	$	4.76	$	1,287		$	2.17		$	1,834		$	3.16

DVP

Presented below are operating statistics related to DVP’s operations:


Year Ended December 31,	2010		% Change			2009		% Change			2008
Electricity delivered (million MWh)		84.5		4	%		81.4		(3	)%		84.0
Degree days:
Cooling⁽¹⁾		2,090		42			1,477		(9	)		1,621
Heating⁽²⁾		3,819		2			3,747		9			3,426
Average electric distribution customer accounts (thousands)⁽³⁾		2,422		1			2,404		1			2,386
Average retail energy marketing customer accounts (thousands)⁽³⁾		2,037		19			1,718		7			1,601

(1)

Cooling degree days are units measuring the extent to which the average daily temperature is greater than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.

(2)

Heating degree days are units measuring the extent to which the average daily temperature is less than 65 degrees, and are calculated as the difference between 65 degrees and the average temperature for that day.

(3)

Thirteen-month average.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:

2010 VS. 2009


	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	48		$	0.08
FERC transmission revenue		40			0.07
Other		(4	)		(0.01	)
Depreciation and amortization		(15	)		(0.03	)
Storm damage and service restoration-distribution operations⁽¹⁾		(11	)		(0.02	)
Other		6			0.01
Share accretion		—			0.01
Change in net income contribution	$	64		$	0.11

(1)

Reflects an increase in storm damage and service restoration costs associated with electric distribution operations resulting from more severe weather during 2010.

2009 VS. 2008


	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
FERC transmission revenue	$	28		$	0.05
Customer growth		5			0.01
Other⁽¹⁾		(14	)		(0.02	)
Storm damage and service restoration-distribution operations⁽²⁾		5			0.01
Depreciation and amortization		(7	)		(0.01	)
Other		(13	)		(0.03	)
Share dilution		—			(0.01	)
Change in net income contribution	$	4		$	—

(1)

Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.

(2)

Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009.

Dominion Generation

Presented below are operating statistics related to Dominion Generation’s operations:


Year Ended December 31,	2010		% Change		2009		% Change		2008
Electricity supplied (million MWh):
Utility		84.5		4%		81.4		(3)%		84.0
Merchant		47.3		(1)		48.0		6		45.3
Degree days (electric utility service area):
Cooling		2,090		42		1,477		(9)		1,621
Heating		3,819		2		3,747		9		3,426

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:

2010 VS. 2009


	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Regulated electric sales:
Weather	$	104		$	0.18
Rate adjustment clause revenue		95			0.16
Other		(23	)		(0.04	)
Outage costs		29			0.05
Other O&M expenses⁽¹⁾		32			0.05
PJM ancillary services		27			0.05
Merchant generation margin		(209	)		(0.36	)
Income and other taxes⁽²⁾		(44	)		(0.08	)
Other		(1	)		—
Share accretion		—			0.02
Change in net income contribution	$	10		$	0.03

(1)

Reflects the 2010 implementation of cost containment measures including a workforce reduction program.

(2)

Reflects the absence of 2009 investment tax credits related to Fowler Ridge and a decrease in the domestic production activities deduction, primarily due to the absence of a 2009 benefit from the remeasurement of tax uncertainties related to this deduction, as well as the 2010 impact of bonus depreciation on this deduction.

2009 VS. 2008


	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Merchant generation margin	$	95		$	0.16
Outage costs		7			0.01
Regulated electric sales:
Customer growth		10			0.02
Rate adjustment clause revenue⁽¹⁾		53			0.09
Other⁽²⁾		(59	)		(0.10	)
Depreciation and amortization		(42	)		(0.07	)
Sales of emissions allowances		(18	)		(0.03	)
Other		8			0.01
Share dilution		—			(0.04	)
Change in net income contribution	$	54		$	0.05

(1)

Reflects the incremental impact of Rider S.

(2)

Primarily reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors.

Dominion Energy

Presented below are selected operating statistics related to Dominion Energy’s operations. As discussed in Note 4, in April 2010 Dominion completed the sale of substantially all of its Appalachian E&P operations. As a result, production-related operating statistics for the Dominion Energy segment are no longer significant.


Year Ended December 31,	2010		% Change		2009		% Change		2008
Gas distribution throughput (bcf):
Sales		31		(28)%		43		(31)%		62
Transportation		241		16		208		(8)		225
Heating degree days		5,682		(3)		5,847		(4)		6,065
Average gas distribution customer accounts (thousands)⁽¹⁾:
Sales		260		(19)		321		(36)		503
Transportation		1,042		5		988		21		814

(1)

Thirteen-month average.

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:

2010 VS. 2009


	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
E&P disposed operations	$	(61	)	$	(0.11	)
Producer services		(27	)		(0.05	)
Gas distribution margin:
AMR and PIR revenue⁽¹⁾		11			0.02
Base gas sale⁽²⁾		10			0.02
Weather		(2	)		—
Other		15			0.03
Cove Point expansion revenue		20			0.03
Other		(8	)		(0.02	)
Share accretion		—			0.01
Change in net income contribution	$	(42	)	$	(0.07	)

(1)

Primarily reflects an allowed return on investment through the AMR and PIR programs.

(2)

Reflects East Ohio’s sale of 3 bcf of base gas in December 2010 as the Company determined that it could operate its storage system and meet existing and anticipated contractual commitments with less base gas.

2009 VS. 2008


	Increase (Decrease)
	Amount			EPS
(millions, except EPS)
Cove Point expansion revenue	$	88		$	0.15
DD&A-gas and oil		28			0.04
Producer services		10			0.02
Gas and oil-production⁽¹⁾		(63	)		(0.11	)
Change in state tax legislation⁽²⁾		(16	)		(0.02	)
Share dilution		—			(0.02	)
Change in net income contribution	$	47		$	0.06

(1)

Primarily reflects a decrease in volumes associated with VPP royalty interests that expired in February 2009.

(2)

Reflects the absence of a 2008 benefit resulting from the reduction of deferred tax liabilities related to the enactment of West Virginia income tax rate reductions.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results:


Year Ended December 31,	2010			2009			2008
(millions, except EPS amounts)
Specific items attributable to operating segments	$	1,014		$	(688	)	$	(134	)
Specific items attributable to Corporate and Other segment:
Peoples discontinued operations		(155	)		26			192
Other		(22	)		7			(61	)
Total specific items		837			(655	)		(3	)
Other corporate operations		(243	)		(240	)		(240	)
Total net benefit (expense)	$	594		$	(895	)	$	(243	)
EPS impact	$	1.01		$	(1.51	)	$	(0.41	)

TOTAL SPECIFIC ITEMS

Corporate and Other includes specific items attributable to Dominion’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 27 to the Consolidated Financial Statements for discussion of these items.

VIRGINIA POWER

RESULTS OF OPERATIONS

Presented below is a summary of Virginia Power’s consolidated results:


Year Ended December 31,	2010		$ Change		2009		$ Change			2008
(millions)
Net Income	$	852	$	496	$	356	$	(508	)	$	864

Overview

2010 VS. 2009

Net income increased by 139%, primarily reflecting the absence of a charge in connection with the settlement of the 2009 base rate case proceedings, favorable weather and a benefit from rate adjustment clauses, partially offset by charges related to a workforce reduction program.

2009 VS. 2008

Net income decreased 59%, primarily due to a charge in connection with the settlement of the 2009 base rate case proceedings and an increase in outage costs related to scheduled outages at certain nuclear and fossil generating facilities.

Analysis of Consolidated Operations

Presented below are selected amounts related to Virginia Power’s results of operations:


Year Ended December 31,	2010		$ Change			2009		$ Change			2008
(millions)
Operating Revenue	$	7,219	$	635		$	6,584	$	(350	)	$	6,934
Electric fuel and other energy-related purchases		2,495		(477	)		2,972		265			2,707
Purchased electric capacity		449		40			409		(1	)		410
Net Revenue		4,275		1,072			3,203		(614	)		3,817
Other operations and maintenance		1,745		122			1,623		218			1,405
Depreciation and amortization		671		30			641		33			608
Other taxes		218		27			191		8			183
Other income		100		(4	)		104		52			52
Interest and related charges		347		(2	)		349		40			309
Income tax expense		542		395			147		(353	)		500

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

An analysis of Virginia Power’s results of operations follows:

2010 VS. 2009

Net Revenue increased 33%, primarily reflecting:

The absence of a charge for the settlement of the 2009 base rate case proceedings ($570 million);

The impact of Riders C1 and C2, R, S and T ($279 million);

An increase in sales to retail customers primarily due to an increase in cooling degree days ($248 million); and

An increase in ancillary revenues received from PJM ($78 million), primarily reflecting an increase in the scheduled dispatch of gas and oil-fired generation units to meet higher demand.

These increases were partially offset by:

A decrease primarily due to the impact of unfavorable economic conditions on customer usage and other factors ($75 million).

Other operations and maintenance increased 8%, primarily reflecting:

A $177 million net increase in salaries, wages and benefits primarily due to a workforce reduction program. As a result of the program, Virginia Power expects to avoid future annualized operations and maintenance expenses of approximately $50 million that would have otherwise been incurred;

A $42 million increase in certain electric transmission-related expenditures; and

A $19 million increase in storm damage and service restoration costs.

These increases were partially offset by:

The absence of a $130 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings.

Depreciation and amortization expense increased 5%, primarily due to property additions.

Other taxes increased 14%, primarily reflecting additional property tax due to increased investments and higher rates ($12 million), incremental use tax that is recoverable through a customer surcharge ($8 million) and higher payroll taxes associated with a workforce reduction program ($7 million).

Income tax expense increased $395 million, primarily reflecting higher pretax income in 2010.

2009 VS. 2008

Net Revenue decreased 16%, primarily due to a charge for the settlement of the 2009 base rate case proceedings.

Other operations and maintenance expense increased 16%, primarily reflecting:

A $130 million write-off of previously deferred RTO costs in connection with the settlement of Virginia Power’s 2009 base rate case proceedings;

A $64 million increase in outage costs related to scheduled outages at certain nuclear and fossil generating facilities;

A $43 million increase resulting from higher salaries, wages and benefits largely due to higher pension and other postretirement benefit costs, and other general and administrative costs; and

A $28 million decrease in gains from the sale of emissions allowances.

These increases were partially offset by:

A $29 million decrease largely due to the deferral of transmission-related expenditures collectible under certain rate adjustment clauses.

Depreciation and amortization expense increased 5%, primarily due to property additions.

Other income increased by $52 million primarily due to an increase in the equity component of AFUDC as a result of construction and expansion projects.

Interest and related charges increased 13%, primarily due to the absence of a $23 million benefit related to the redemption of Virginia Power’s Callable and Puttable Enhanced Securities in 2008, and a $17 million impact largely due to the impact from additional borrowings.

Income tax expense decreased 71%, reflecting lower pre-tax income in 2009.

Outlook

Virginia Power expects to provide growth in net income in 2011. Virginia Power’s anticipated 2011 results reflect the following significant factors:

Growth in electric sales resulting from the recovering economy;

A benefit from rate adjustment clause revenue associated with Bear Garden and Virginia City Hybrid Energy Center;

Lower outage costs at certain generating facilities; partially offset by

A return to normal weather in its electric utility operations.

Virginia Power also expects the bonus depreciation provisions of the tax legislation recently enacted by the U.S. Congress in 2010, discussed in Note 6 to the Consolidated Financial Statements, to reduce income taxes otherwise payable by $600 million to $1.2 billion during 2011 through 2013. The acceleration of these tax deductions is expected to reduce the domestic production activities income tax deduction through 2012 and will also increase deferred taxes, thereby reducing the regulated rate base. However, Virginia Power plans to partially mitigate the earnings impact of these items by using the cash tax savings to reduce the amount of debt that would have otherwise been issued over the next three years.

SEGMENT RESULTS OF OPERATIONS

Presented below is a summary of contributions by Virginia Power’s operating segments to net income:


Year Ended December 31,	2010			$ Change		2009			$ Change			2008
(millions)
DVP	$	377		$	64	$	313		$	6		$	307
Dominion Generation		630			155		475			(108	)		583
Primary operating segments		1,007			219		788			(102	)		890
Corporate and Other		(155	)		277		(432	)		(406	)		(26	)
Consolidated	$	852		$	496	$	356		$	(508	)	$	864

DVP

Presented below are operating statistics related to Virginia Power’s DVP segment:


Year Ended December 31,	2010		% Change		2009		% Change			2008
Electricity delivered (million MWh)		84.5		4%		81.4		(3	)%		84.0
Degree days (electric service area):
Cooling⁽¹⁾		2,090		42		1,477		(9	)		1,621
Heating⁽²⁾		3,819		2		3,747		9			3,426
Average electric distribution customer accounts (thousands)⁽³⁾		2,422		1		2,404		1			2,386

(1)

(2)

(3)

Thirteen-month average.

Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:

2010 VS. 2009


	Increase (Decrease)
(millions, except EPS)
Regulated electric sales:
Weather	$	48
FERC transmission revenue		40
Other		(4	)
Depreciation and amortization		(15	)
Storm damage and service restoration—distribution operations⁽¹⁾		(11	)
Other		6
Change in net income contribution	$	64

(1)

Reflects an increase in storm damage and service restoration costs associated with electric distribution operations resulting from more severe weather during 2010.

2009 VS. 2008


	Increase (Decrease)
(millions)
Regulated electric sales:
FERC transmission revenue	$	28
Customer growth		5
Other⁽¹⁾		(14	)
Storm damage and service restoration—distribution operations⁽²⁾		5
Depreciation and amortization		(7	)
Other		(11	)
Change in net income contribution	$	6

(1)

Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.

(2)

Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009.

Dominion Generation

Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:


Year Ended December 31,	2010		% Change		2009		% Change		2008
Electricity supplied (million MWh)		84.5		4%		81.4		(3)%		84.0
Degree days (electric service area):
Cooling		2,090		42		1,477		(9)		1,621
Heating		3,819		2		3,747		9		3,426

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:

2010 VS. 2009


	Increase (Decrease)
(millions)
Regulated electric sales:
Weather	$	104
Rate adjustment clause revenue		95
Other		(23	)
PJM ancillary services		27
Income and other taxes⁽¹⁾		(24	)
Energy supply margin⁽²⁾		(13	)
Other		(11	)
Change in net income contribution	$	155

(1)

Reflects a decrease in the domestic production activities deduction, primarily due to the absence of a 2009 benefit from the remeasurement of tax uncertainties related to this deduction, as well as the 2010 impact of bonus depreciation on this deduction.

(2)

Primarily reflects a reduced benefit from FTRs, due to the crediting of certain FTRs allocated to Virginia Power against Virginia jurisdictional fuel factor expenses subject to deferral accounting beginning July 1, 2009.

2009 VS. 2008


	Increase (Decrease)
(millions)
Outage costs	$	(36	)
PJM ancillary services		(21	)
Sale of emissions allowances		(17	)
Interest expense		(15	)
Depreciation expense		(13	)
Regulated electric sales:
Customer growth		10
Rate adjustment clause revenue⁽¹⁾		53
Other⁽²⁾		(59	)
Other		(10	)
Change in net income contribution	$	(108	)

(1)

Reflects the incremental impact of Rider S.

(2)

Primarily reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors.

Corporate and Other

Presented below are the Corporate and Other segment’s after-tax results.


Year Ended December 31,	2010			2009			2008
(millions)
Specific items attributable to operating segments	$	(153	)	$	(430	)	$	(23	)
Other corporate operations		(2	)		(2	)		(3	)
Total net expense	$	(155	)	$	(432	)	$	(26	)

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

SPECIFIC ITEMS ATTRIBUTABLE TO OPERATING SEGMENTS

Corporate and Other primarily includes specific items attributable to Virginia Power’s primary operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 27 to the Consolidated Financial Statements for a discussion of these items.

LIQUIDITY AND CAPITAL RESOURCES

Dominion and Virginia Power depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through issuances of debt and/or equity securities.

At December 31, 2010, Dominion had $2 billion of unused capacity under its credit facilities, including $559 million of unused capacity under joint credit facilities available to Virginia Power. See additional discussion under Credit Facilities and Short-Term Debt.

A summary of Dominion’s cash flows is presented below:


Year Ended December 31,	2010			2009			2008
(millions)
Cash and cash equivalents at beginning of year	$	50		$	71		$	287
Cash flows provided by (used in):
Operating activities		1,825			3,786			2,676
Investing activities		419			(3,695	)		(3,490	)
Financing activities		(2,232	)		(112	)		598
Net increase (decrease) in cash and cash equivalents		12			(21	)		(216	)
Cash and cash equivalents at end of year⁽¹⁾	$	62		$	50		$	71

(1)

2009 and 2008 amounts include $2 million and $5 million, respectively, of cash classified as held for sale in Dominion’s Consolidated Balance Sheets.

A summary of Virginia Power’s cash flows is presented below:


Year Ended December 31,	2010			2009			2008
(millions)
Cash and cash equivalents at beginning of year	$	19		$	27		$	49
Cash flows provided by (used in):
Operating activities		1,409			1,970			1,235
Investing activities		(2,425	)		(2,568	)		(2,003	)
Financing activities		1,002			590			746
Net decrease in cash and cash equivalents		(14	)		(8	)		(22	)
Cash and cash equivalents at end of year	$	5		$	19		$	27

Operating Cash Flows

In 2010, net cash provided by Dominion’s operating activities decreased by approximately $2 billion, primarily due to lower deferred fuel and gas cost recoveries, contributions to Dominion’s pension plans, the absence of disposed Appalachian E&P operations, lower merchant generation margins and refunds related to the 2009 Virginia Power base rate case settlement, partially offset

by lower income tax payments, lower margin collateral requirements and the favorable impact of weather and rate adjustment clauses on electric utility operations.

In 2010, net cash provided by Virginia Power’s operating activities decreased by $561 million, primarily due to lower deferred fuel cost recoveries in its Virginia jurisdiction, refunds related to the 2009 Virginia base rate case settlement, and contributions to Dominion’s pension plans; partially offset by the favorable impact of weather and rate adjustment clauses, and cash received for income tax benefits in 2010, as compared to income taxes paid in 2009.

Dominion’s lower income tax payments and Virginia Power’s realization of income tax benefits in 2010 resulted in part from the bonus depreciation provisions of the tax legislation recently enacted by the U.S. Congress, discussed in Note 6 to the Consolidated Financial Statements.

Dominion believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares. In 2011, Dominion’s board of directors adopted a new dividend policy that raised its target payout ratio. The Board established an annual dividend rate of $1.97 per share of common stock, a 7.7% increase over the 2010 rate. Quarterly dividends are subject to declaration by the Board. Virginia Power believes that its operations provide a stable source of cash flow to contribute to planned levels of capital expenditures and provide dividends to Dominion.

The Companies’ operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flows which are discussed in Item 1A. Risk Factors.

CREDIT RISK

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy marketing and price risk management activities. Presented below is a summary of Dominion’s credit exposure as of December 31, 2010 for these activities. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on or off-balance sheet exposure, taking into account contractual netting rights.


	Gross Credit Exposure		Credit Collateral		Net Credit Exposure
(millions)
Investment grade⁽¹⁾	$	426	$	26	$	400
Non-investment grade⁽²⁾		10		3		7
No external ratings:
Internally rated-investment grade⁽³⁾		102		—		102
Internally rated-non-investment grade⁽⁴⁾		82		—		82
Total	$	620	$	29	$	591

(1)

Designations as investment grade are based upon minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 33% of the total net credit exposure.

(2)

The five largest counterparty exposures, combined, for this category represented approximately 1% of the total net credit exposure.

(3)

The five largest counterparty exposures, combined, for this category represented approximately 11% of the total net credit exposure.

(4)

The five largest counterparty exposures, combined, for this category represented approximately 8% of the total net credit exposure.

Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers and is not considered material at December 31, 2010.

Investing Cash Flows

In 2010, net cash provided by Dominion’s investing activities was $419 million as compared to net cash used in investing activities of $3.7 billion in 2009. This change is primarily due to the proceeds received from the sale of substantially all of Dominion’s Appalachian E&P operations in April 2010 and the sale of Peoples in February 2010. While taxes and other costs of the sales are reflected in cash flow from operations, the gross proceeds from the sales are reported in cash flow from investing activities.

In 2010, net cash used in Virginia Power’s investing activities decreased by $143 million, primarily due to lower capital expenditures, partially offset by an increase in restricted cash equivalents designated to finance certain qualifying facilities.

Financing Cash Flows and Liquidity

Dominion and Virginia Power rely on capital markets as significant sources of funding for capital requirements not satisfied by cash provided by their operations. As discussed in Credit Ratings, the Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by credit ratings. In addition, the raising of external capital is subject to certain regulatory requirements, including registration with the SEC for certain issuances and, in the case of Virginia Power, approval by the Virginia Commission.

Each of the Companies currently meets the definition of a well-known seasoned issuer under SEC rules governing the registration, communications and offering processes under the Securities Act of 1933. The rules provide for a streamlined shelf registration process to provide registrants with timely access to capital. This allows the Companies to use automatic shelf registration statements to register any offering of securities, other than those for business combination transactions.

In 2010, net cash used in Dominion’s financing activities increased by $2.1 billion, primarily due to net debt repayments in 2010 as compared to net debt issuances in 2009, and net repurchases of common stock in 2010 as compared to issuances of common stock in 2009. This reflects the use of proceeds from the sales of Dominion’s Appalachian E&P operations and Peoples.

In 2010, net cash provided by Virginia Power’s financing activities increased by $412 million, primarily due to higher net debt issuances in 2010 as compared to 2009, as a result of lower cash flow from operations.

CREDIT FACILITIES AND SHORT-TERM DEBT

Dominion and Virginia Power use short-term debt to fund working capital requirements and as a bridge to long-term debt financings. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. In addition, Dominion utilizes cash and letters of credit to fund collateral requirements. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit ratings and the credit quality of its counterparties. Dominion and Virginia Power replaced certain of their existing credit facilities in September 2010, as noted below.

In connection with commodity hedging activities, the Companies are required to provide collateral to counterparties under some circumstances. Under certain collateral arrangements, the Companies may satisfy these requirements by electing to either deposit cash, post letters of credit or, in some cases, utilize other forms of security. From time to time, the Companies vary the form of collateral provided to counterparties after weighing the costs and benefits of various factors associated with the different forms of collateral. These factors include short-term borrowing and short-term investment rates, the spread over these short-term rates at which the Companies can issue commercial paper, balance sheet impacts, the costs and fees of alternative collateral postings with these and other counterparties and overall liquidity management objectives.

DOMINION

Commercial paper and letters of credit outstanding, as well as capacity available under credit facilities were as follows:

At December 31, 2010

Facility
Limit

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

Facility
Capacity
Available

(millions)

Three-year joint revolving credit facility⁽¹⁾

3,000

1,386

101

1,513

Three-year joint revolving credit facility⁽²⁾

500

—

465

Total

3,500

1,386

⁽³⁾

136

1,978

(1)

(2)

This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances.

(3)

The weighted-average interest rate of the outstanding commercial paper supported by Dominion’s credit facilities was 0.41% at December 31, 2010.

VIRGINIA POWER

Virginia Power’s short-term financing is supported by two three-year joint revolving credit facilities with Dominion. These credit facilities are being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Power and for other general corporate purposes.

Virginia Power’s share of commercial paper and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion were as follows:


At December 31, 2010	Facility Sub-limit		Outstanding Commercial Paper			Outstanding Letters of Credit		Facility Capacity Available
(millions)
Three-year joint revolving credit facility⁽¹⁾	$	1,000	$	600		$	91	$	309
Three-year joint revolving credit facility⁽²⁾		250		—			—		250
Total	$	1,250	$	600	⁽³⁾	$	91	$	559

(1)

This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings and the issuance of commercial paper, as well as to support up to $1.5 billion (or the sub-limit, whichever is less) of letters of credit. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

(2)

This credit facility was entered into in September 2010 and terminates in September 2013. This credit facility can be used to support bank borrowings, commercial paper and letter of credit issuances. Virginia Power’s current sub-limit under this credit facility can be increased or decreased multiple times per year.

(3)

The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 0.41% at December 31, 2010.

In addition to the credit facility commitments mentioned above, Virginia Power also has a three-year $120 million credit facility that was entered into in September 2010. The facility, which terminates in September 2013, supports certain tax-exempt financings of Virginia Power.

LONG-TERM DEBT

During 2010, Dominion and Virginia Power issued the following long-term debt:

Type

Principal

Rate

Maturity

Issuing
Company

(millions)

Senior notes

250

2.25

2015

Dominion

Senior notes

300

3.45

2022

Virginia Power

Total notes issued

550

In November 2010, Virginia Power borrowed $105 million in connection with the Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2010 A, which mature in 2040 and bear a coupon rate of 2.375% for the first five years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds will be used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center.

In December 2010 and September 2009, Virginia Power borrowed $100 million and $60 million, respectively, in connection with the $160 million Industrial Development Authority of Wise County Solid Waste and Sewage Disposal Revenue Bonds, Series 2009 A, which mature in 2040 and bear interest during the initial period at a variable rate. Due to unfavorable market conditions, Virginia Power acquired the bonds upon issuance with the intention of remarketing them to third parties at a later time. The proceeds will be used to finance certain qualifying facilities at the Virginia City Hybrid Energy Center. At December 31, 2010, these bonds had not been remarketed and thus are not reflected on the Consolidated Balance Sheets.

In December 2010, Virginia Power borrowed $100 million in connection with the Industrial Development Authority of Halifax County, Virginia Recovery Zone Facility Revenue Bonds, Series 2010 A, which mature in 2041 and bear interest at a variable rate for the first seven years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds will be used to finance certain qualifying facilities in Halifax County and/or Wise County.

In December 2010, Brayton Point borrowed approximately $160 million and approximately $75 million in connection with the Massachusetts Development Finance Agency Recovery Zone Facility Bonds, Series 2010 A and the Solid Waste Disposal Revenue Bonds, Series 2010 B, respectively, which mature in 2041 and bear interest during the initial period at a variable rate. Due to unfavorable market conditions, Dominion acquired the bonds upon issuance in December 2010 with the intention of remarketing them to third parties at a later time. The proceeds

will be used to finance certain qualifying facilities at Brayton Point. At December 31, 2010, these bonds had not been remarketed and thus are not reflected on the Consolidated Balance Sheets.

During 2010, Dominion and Virginia Power repaid and repurchased $1.5 billion and $347 million, respectively, of long-term debt and notes payable.

ISSUANCE OF COMMON STOCK

During 2010, Dominion issued 2.3 million shares of common stock for cash proceeds of $74 million. The shares issued and cash proceeds received during 2010 were through Dominion Direct^®, employee savings plans and the exercise of employee stock options. Dominion does not currently plan any market issuances of common stock in 2011 or 2012.

In February 2010, Dominion began purchasing its common stock on the open market with proceeds received through Dominion Direct^® and employee savings plans, rather than issuing additional new common shares.

In 2010, Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion. The proceeds were used to pay down short-term demand note borrowings from Dominion.

REPURCHASE OF COMMON STOCK

In March 2010, Dominion began repurchasing common shares in anticipation of proceeds from the sale of its Appalachian E&P operations. During 2010, Dominion purchased 21.4 million shares of its common stock for approximately $900 million.

On January 28, 2011, Dominion announced that it intends to repurchase between $400 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance discussed in Note 6 to the Consolidated Financial Statements. In the first quarter of 2011, Dominion began repurchasing shares on the open market under this program.

BORROWINGS FROM PARENT

Virginia Power has the ability to borrow funds from Dominion under both short-term and long-term borrowing arrangements and at December 31, 2010, its nonregulated subsidiaries had outstanding borrowings, net of repayments, under the Dominion money pool of $24 million. Virginia Power’s short-term demand note borrowings from Dominion were $79 million at December 31, 2010. There were no long-term borrowings from Dominion at December 31, 2010.

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Dominion and Virginia Power believe that their current credit ratings provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion and Virginia Power may affect their ability to access these funding sources or cause an increase in the return required by investors. Dominion’s and Virginia Power’s credit ratings may affect their liquidity, cost of borrowing under credit facilities and collateral posting requirements under commodity contracts, as well as the rates at which they are able to offer their debt securities.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for Dominion and Virginia Power are most affected by each company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and event risk, if applicable, such as major acquisitions or dispositions.

In January 2010, Fitch lowered its credit ratings for Virginia Power’s preferred stock and Dominion’s junior subordinated debt securities and enhanced junior subordinated notes solely due to a revision in Fitch’s ratings methodology such that it now rates these securities two notches below its credit rating for senior unsecured debt securities. In December 2010, Moody’s raised its credit ratings for Virginia Power, reflecting sustained improvements in Virginia Power’s financial performance as measured by its credit metrics and the agency’s views of a generally supportive regulatory and political environment in Virginia Power’s service territory.

Credit ratings as of February 23, 2011 follow:

Fitch

Moody’s

Standard
& Poor’s

Dominion

Senior unsecured debt securities

BBB+

Baa2

A-

Junior subordinated debt securities

BBB-

Baa3

BBB

Enhanced junior subordinated notes

BBB-

Baa3

BBB

Commercial paper

P-2

A-2

Virginia Power

Mortgage bonds

Senior unsecured (including tax-exempt) debt securities

A-

Junior subordinated debt securities

BBB

Baa1

BBB

Preferred stock

BBB

Baa2

BBB

Commercial paper

P-2

A-2

As of February 23, 2011, Fitch, Moody’s and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion and Virginia Power.

A downgrade in an individual company’s credit rating would not necessarily restrict its ability to raise short-term and long-term financing as long as its credit rating remains investment grade, but it would likely increase the cost of borrowing. Dominion and Virginia Power work closely with Fitch, Moody’s and Standard & Poor’s with the objective of maintaining their current credit ratings. In order to maintain current ratings, the Companies may find it necessary to modify their business plans and such changes may adversely affect growth and EPS.

Debt Covenants

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, Dominion and Virginia Power must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the

lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to Dominion and Virginia Power.

Some of the typical covenants include:

The timely payment of principal and interest;

Information requirements, including submitting financial reports filed with the SEC and information about changes in Dominion’s and Virginia Power’s credit ratings to lenders;

Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, and restrictions on disposition of all or substantially all assets;

Compliance with collateral minimums or requirements related to mortgage bonds; and

Limitations on liens.

Dominion and Virginia Power are required to pay annual commitment fees to maintain their credit facilities. In addition, their credit agreements contain various terms and conditions that could affect their ability to borrow under these facilities. They include maximum debt to total capital ratios and cross-default provisions.

As of December 31, 2010, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:


Company	Maximum Allowed Ratio			Actual Ratio⁽¹⁾
Dominion		65	%		54	%
Virginia Power		65	%		46	%

(1)

Indebtedness as defined by the bank agreements excludes junior subordinated notes reflected as long-term debt as well as AOCI reflected as equity in the Consolidated Balance Sheets.

These provisions apply separately to Dominion and Virginia Power. If Dominion or Virginia Power or any of either company’s material subsidiaries fails to make payment on various debt obligations in excess of $100 million, the lenders could require that company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to that company. Accordingly, any default by Dominion will not affect the lenders’ commitment to Virginia Power. However, any default by Virginia Power would affect the lenders’ commitment to Dominion under the joint credit agreements.

Dominion executed RCCs in connection with its issuance of the following hybrid securities:

June 2006 hybrids;

September 2006 hybrids; and

June 2009 hybrids.

Under the terms of the RCCs, Dominion covenants to and for the benefit of designated covered debtholders, as may be designated from time to time, that Dominion shall not redeem, repurchase, or defease all or any part of the hybrids, and shall not cause its majority owned subsidiaries to purchase all or any part of the hybrids, on or before their applicable RCC termination date, unless, subject to certain limitations, during the 180 days prior to such activity, Dominion has received a specified amount of proceeds as set forth in the RCCs from the sale of qualifying securities that have equity-like characteristics that are the same as, or more equity-like than the applicable characteristics of the hybrids

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

at that time, as more fully described in the RCCs. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must equal or exceed the redemption or repurchase price.

At December 31, 2010, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids are as follows:


Hybrid	RCC Termination Date			Designated Covered Debt Under RCC
June 2006 hybrids		6/30/2036		September 2006 hybrids
September 2006 hybrids		9/30/2036		June 2006 hybrids
June 2009 hybrids		6/15/2034	⁽¹⁾	2008 Series B Senior Notes, 7.0% due 2038

(1)

Automatically extended, as set forth in the RCC, for additional quarterly periods, to the extent the maturity date is extended.

Dominion and Virginia Power monitor the debt covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2010, there have been no events of default under or changes to Dominion’s debt covenants.

Dividend Restrictions

The Virginia Commission may prohibit any public service company, including Virginia Power, from declaring or paying a dividend to an affiliate if found to be detrimental to the public interest. At December 31, 2010, the Virginia Commission had not restricted the payment of dividends by Virginia Power.

Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2010.

See Note 18 to the Consolidated Financial Statements for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.

Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

CONTRACTUAL OBLIGATIONS

Dominion and Virginia Power are party to numerous contracts and arrangements obligating them to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion and Virginia Power are parties as of December 31, 2010. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities in the Consolidated Balance Sheets, other than current maturities of long-term debt, interest payable and certain derivative instruments. The majority of Dominion’s and Virginia Power’s current liabilities will be paid in cash in 2011.

Dominion

2011

2012-
2013

2014-
2015

2016 and
thereafter

Total

(millions)

Long-term debt⁽¹⁾

497

2,184

1,666

11,882

16,229

Interest payments⁽²⁾

932

1,786

1,592

12,996

17,306

Leases⁽³⁾

184

312

108

193

797

Purchase obligations⁽⁴⁾:

Purchased electric capacity for utility operations

342

698

696

779

2,515

Fuel commitments for utility operations

959

932

491

241

2,623

Fuel commitments for nonregulated operations

446

264

198

162

1,070

Pipeline transportation and storage

134

142

389

Energy commodity purchases for resale⁽⁵⁾

495

638

Other⁽⁶⁾

253

331

Other long-term liabilities⁽⁷⁾:

Financial derivative-commodities⁽⁵⁾

Other contractual obligations⁽⁸⁾

Total cash payments

4,275

6,488

4,845

26,408

42,016

(1)

Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

(2)

Does not reflect Dominion’s ability to defer interest payments on junior subordinated notes.

(3)

Primarily consists of operating leases.

(4)

Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

(5)

Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among its counterparties and Dominion were liquidated and terminated.

(6)

Includes capital, operations and maintenance commitments.

(7)

Excludes regulatory liabilities, AROs and employee benefit plan obligations, which are not contractually fixed as to timing and amount. See Notes 13, 15 and 22 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $253 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 6 to the Consolidated Financial Statements.

(8)

Includes interest rate swap agreements.

Virginia Power

2011

2012-
2013

2014-
2015

2016 and
thereafter

Total

(millions)

Long-term debt⁽¹⁾

1,034

236

5,436

6,721

Interest payments

369

721

653

4,418

6,161

Leases⁽²⁾

130

Purchase obligations⁽³⁾:

Purchased electric capacity for utility operations

342

698

696

779

2,515

Fuel commitments for utility operations

959

932

491

241

2,623

Transportation and storage

101

Other

113

150

Total cash payments⁽⁴⁾

1,853

3,480

2,131

10,937

18,401

(1)

Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.

(2)

Primarily consists of operating leases.

(3)

Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.

(4)

Excludes regulatory liabilities, AROs and employee benefit plan contributions that are not contractually fixed as to timing and amount. See Notes 13, 15 and 22 to the Consolidated Financial Statements. Due to uncertainty about the timing and amounts that will ultimately be paid, $113 million of income taxes payable associated with unrecognized tax benefits are excluded. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year. See Note 6 to the Consolidated Financial Statements.

PLANNED CAPITAL EXPENDITURES

Dominion’s planned capital expenditures are expected to total approximately $3.9 billion, $4.7 billion and $4.4 billion in 2011, 2012 and 2013, respectively. Dominion’s expenditures are expected to include construction and expansion of electric generation and natural gas transmission and storage facilities, environmental upgrades, construction improvements and expansion of electric transmission and distribution assets and purchases of nuclear fuel.

Virginia Power’s planned capital expenditures are expected to total approximately $2.2 billion, $3.0 billion and $3.3 billion in 2011, 2012 and 2013, respectively. Virginia Power’s expenditures are expected to include construction and expansion of electric generation facilities, environmental upgrades, construction improvements and expansion of electric transmission and distribution assets and purchases of nuclear fuel.

Dominion and Virginia Power expect to fund their capital expenditures with cash from operations and a combination of securities issuances and short-term borrowings. Planned capital expenditures include capital projects that are subject to approval by regulators and the Board of Directors.

Based on available generation capacity and current estimates of growth in customer demand, Virginia Power will need additional generation in the future. See Dominion Generation-Properties in Item 1. Business for a discussion of Virginia Power’s expansion plans.

These estimates are subject to continuing review and adjustment and actual capital expenditures may vary from these estimates. The Companies may also choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings and equity issuances.

Use of Off-Balance Sheet Arrangements

GUARANTEES

Dominion primarily enters into guarantee arrangements on behalf of its consolidated subsidiaries. These arrangements are not subject to the provisions of FASB guidance that dictate a guarantor’s accounting and disclosure requirements for guarantees, including indirect guarantees of indebtedness of others.

LEASING ARRANGEMENT

Dominion leases Fairless in Pennsylvania, which began commercial operations in June 2004. During construction, Dominion

acted as the construction agent for the lessor, controlled the design and construction of the facility and has since been reimbursed for all project costs ($898 million) advanced to the lessor. Dominion makes annual lease payments of $53 million. The lease expires in 2013 and at that time, Dominion may renew the lease at negotiated amounts based on original project costs and current market conditions, subject to lessor approval; purchase Fairless at its original construction cost plus 51% of any appraised value in excess of original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events.

Benefits of this arrangement include:

Certain tax benefits as Dominion is considered the owner of the leased property for tax purposes. As a result, Dominion is entitled to tax deductions for depreciation not recognized for financial accounting purposes; and

As an operating lease for financial accounting purposes, the asset and related borrowings used to finance the construction of the asset are not included in the Consolidated Balance Sheets. Although this improves measures of leverage calculated using amounts reported in the Consolidated Financial Statements, credit rating agencies view lease obligations as debt equivalents in evaluating Dominion’s credit profile.

FUTURE ISSUES AND OTHER MATTERS

See Item 1. Business, Item 3. Legal Proceedings, and Notes 14 and 23 to the Consolidated Financial Statements for additional information on various environmental, regulatory, legal and other matters that may impact future results of operations and/or financial condition.

Environmental Matters

Dominion and Virginia Power are subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations.

ENVIRONMENTAL PROTECTION AND MONITORING EXPENDITURES

Dominion incurred approximately $228 million, $252 million and $205 million of expenses (including depreciation) during 2010, 2009, and 2008 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $231 million and $251 million in 2011 and 2012, respectively. In addition, capital expenditures related to environmental controls were $351 million, $266 million, and $254 million for 2010, 2009 and 2008, respectively. These expenditures are expected to be approximately $398 million and $553 million for 2011 and 2012, respectively.

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

Virginia Power incurred approximately $144 million, $134 million and $125 million of expenses (including depreciation) during 2010, 2009 and 2008, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $142 million and $156 million in 2011 and 2012, respectively. In addition, capital expenditures related to environmental controls were $101 million, $109 million and $116 million for 2010, 2009 and 2008, respectively. These expenditures are expected to be approximately $72 million and $341 million for 2011 and 2012, respectively.

FUTURE ENVIRONMENTAL REGULATIONS

There have already been federal and state legislative proposals and regulatory action regarding the regulation of GHG emissions. Dominion and Virginia Power expect that there may be federal legislation and/or regulatory action regarding compliance with more stringent air emission standards, regarding coal combustion by-products, and regarding regulation of cooling water intake structures and discharges in the future. With respect to GHG emissions, in December 2010, the EPA announced a schedule for when they will propose regulations which would establish GHG performance standards for new, modified and existing fossil-fired electric generating units. Regulations are expected to be proposed by July 2011 and finalized by May 2012. This means that Dominion’s new, modified, and existing fossil-fired electric generating units will become subject to GHG performance standards, if these rules are finalized. The EPA has not provided any detail yet on what the performance standard might be or what measures facilities might have to make to reach the standard. With respect to emission reductions of SO₂, NO_x, mercury and HAPs (in addition to mercury), specific requirements will depend on the following:

Final outcome of the EPA’s scheduled rulemaking for developing MACT standards for mercury and other HAPs to replace the CAMR vacated by a federal court in 2008;

The final outcome of the EPA’s Transport Rule proposed in July 2010 in response to a federal court remand of the CAIR as well as future state regulations implementing requirements to address the EPA’s promulgation of revised NAAQS for SO₂ and NO_2; and

EPA’s impending rulemaking to revise the ozone NAAQS.

With respect to cooling water intakes and discharges, the Companies expect future federal regulation on cooling water intake structures and the quality of water discharges, and more focus by the EPA and state regulatory authorities on thermal discharge issues. With respect to coal combustion by-products, Dominion and Virginia Power expect federal regulation of coal combustion by-product handling and disposal practices. If any of these new proposals are adopted, additional significant expenditures may be required.

Dodd-Frank Act

The Dodd-Frank Act was enacted into law in July 2010 in an effort to improve regulation of financial markets. The Dodd-Frank Act includes provisions that will require certain over-the-counter derivatives, or swaps, to be centrally cleared and executed through an exchange or other approved trading platform. Non-financial entities that use swaps to hedge or mitigate commercial risk, often referred to as end users, can be exempted from these clearing and exchange trading requirements. In addi-

tion, the Dodd-Frank Act allows the CFTC and SEC to impose initial and variation margin requirements on entities who execute swaps. End users were not expressly exempt from these requirements for non-cleared swaps; however, key legislators indicated in a public letter that it was their intention to exclude commercial hedging transactions by end users from these requirements. Final rules for the over-the-counter derivative-related provisions of the Dodd-Frank Act, including the clearing, exchange trading and margin requirements, will be established through the CFTC’s and SEC’s rulemaking process, which is required to be completed by July 2011. If, as a result of the rulemaking process, Dominion’s or Virginia Power’s derivative activities are not exempted from the clearing, exchange trading or margin requirements, the Companies could be subject to higher costs for their derivative activities, including from higher margin requirements. In addition, implementation of, and compliance with, the over-the-counter derivative provisions of the Dodd-Frank Act by the Companies’ swap counterparties could result in increased costs related to the Companies’ derivative activities. Due to the ongoing rulemaking process, the Companies are currently unable to assess the potential impact of the Dodd-Frank Act’s derivative-related provisions on their financial condition, results of operations or cash flows.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The matters discussed in this Item may contain “forward-looking statements” as described in the introductory paragraphs of Item 7. MD&A. The reader’s attention is directed to those paragraphs and Item 1A. Risk Factors for discussion of various risks and uncertainties that may impact Dominion and Virginia Power.

MARKET RISK SENSITIVE INSTRUMENTS AND RISK MANAGEMENT

Dominion’s and Virginia Power’s financial instruments, commodity contracts and related financial derivative instruments are exposed to potential losses due to adverse changes in commodity prices, interest rates and equity security prices as described below. Commodity price risk is present in Dominion’s and Virginia Power’s electric operations, Dominion’s gas procurement operations, and Dominion’s energy marketing and trading operations due to the exposure to market shifts in prices received and paid for electricity, natural gas and other commodities. The Companies use commodity derivative contracts to manage price risk exposures for these operations. Interest rate risk is generally related to their outstanding debt. In addition, they are exposed to investment price risk through various portfolios of equity and debt securities.

The following sensitivity analysis estimates the potential loss of future earnings or fair value from market risk sensitive instruments over a selected time period due to a 10% unfavorable change in commodity prices or interest rates.

Commodity Price Risk

To manage price risk, Dominion and Virginia Power primarily hold commodity-based financial derivative instruments held for non-trading purposes associated with purchases and sales of elec-

tricity, natural gas and other energy-related products. As part of its strategy to market energy and to manage related risks, Dominion also holds commodity-based financial derivative instruments for trading purposes.

The derivatives used to manage commodity price risk are executed within established policies and procedures and may include instruments such as futures, forwards, swaps, options and FTRs that are sensitive to changes in the related commodity prices. For sensitivity analysis purposes, the hypothetical change in market prices of commodity-based financial derivative instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Prices and volatility are principally determined based on observable market prices.

A hypothetical 10% unfavorable change in market prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $183 million and $150 million as of December 31, 2010 and 2009, respectively. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $5 million and $11 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes as of December 31, 2010 and 2009, respectively.

A hypothetical 10% unfavorable change in commodity prices would not have resulted in a material change in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 2010 or 2009.

The impact of a change in energy commodity prices on Dominion’s and Virginia Power’s non-trading commodity-based financial derivative instruments at a point in time is not necessarily representative of the results that will be realized when the contracts are ultimately settled. Net losses from commodity derivative instruments used for hedging purposes, to the extent realized, will generally be offset by recognition of the hedged transaction, such as revenue from physical sales of the commodity.

Interest Rate Risk

Dominion and Virginia Power manage their interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. They also enter into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments designated under fair value hedging and outstanding for Dominion and Virginia Power, a hypothetical 10% increase in market interest rates would not have resulted in a material change in annual earnings at December 31, 2010 or 2009.

Dominion and Virginia Power may also use forward-starting interest rate swaps and interest rate lock agreements as anticipatory hedges. At December 31, 2009, Dominion and Virginia Power had $1.7 billion and $850 million, respectively, in aggregate notional amounts of these interest rate derivatives outstanding. At December 31, 2009, a hypothetical 10% decrease in market interest rates would have resulted in a decrease of approximately $62 million and $33 million in the fair value of these interest rate derivatives held by Dominion and Virginia Power, respectively. Subsequent to June 30, 2010, all forward-starting

interest rate swap contracts were terminated; therefore, Dominion and Virginia Power have no sensitivity to changes in interest rates related to these interest rate swaps.

The impact of a change in market interest rates on these anticipatory hedges at a point in time is not necessarily representative of the results that will be realized when such contracts are settled. Net gains and/or losses from interest rate derivatives used for anticipatory hedging purposes, to the extent realized, will generally be amortized over the life of the respective debt issuance being hedged.

Investment Price Risk

Dominion and Virginia Power are subject to investment price risk due to securities held as investments in decommissioning and rabbi trust funds that are managed by third-party investment managers. These trust funds primarily hold marketable securities that are reported in the Consolidated Balance Sheets at fair value.

Dominion recognized net realized gains (including investment income) on nuclear decommissioning and rabbi trust investments of $95 million and $25 million in 2010 and 2009, respectively. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2010 and 2009, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $182 million and $360 million, respectively.

Virginia Power recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $44 million in 2010. Virginia Power recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $3 million in 2009. Net realized gains and losses include gains and losses from the sale of investments as well as any other-than-temporary declines in fair value. In 2010 and 2009, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $67 million and $149 million, respectively.

Dominion sponsors pension and other postretirement benefit plans that hold investments in trusts to fund employee benefit payments. Virginia Power employees participate in these plans. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $624 million in 2010 and $777 million in 2009, versus expected returns of $479 million and $462 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans. As of December 31, 2010 and 2009, a hypothetical 0.25% decrease in the assumed long-term rates of return on Dominion’s plan assets would result in an increase in net periodic cost of approximately $13 million for pension benefits and $3 million for other postretirement benefits.

Risk Management Policies

Dominion and Virginia Power have established operating procedures with corporate management to ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the credit and commodity risk management policies

Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2010 and 2009, and the related consolidated statements of income, common shareholders’ equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of Dominion’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, in 2009 Dominion changed its methods of accounting to adopt a new accounting standard for the impairment framework for oil and gas properties.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Dominion’s internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2011 expressed an unqualified opinion on Dominion’s internal control over financial reporting.

The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.

We have audited the accompanying consolidated balance sheets of Virginia Electric and Power Company (a wholly-owned subsidiary of Dominion Resources, Inc.) and subsidiaries (“Virginia Power”) as of December 31, 2010 and 2009, and the related consolidated statements of income, common shareholder’s equity, comprehensive income, and cash flows for each of the three years in the period ended December 31, 2010. These financial statements are the responsibility of Virginia Power’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. Virginia Power is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of Virginia Power’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Virginia Electric and Power Company and subsidiaries as of December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with accounting principles generally accepted in the United States of America.

The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.

NOTE 1. NATURE OF OPERATIONS

Dominion, headquartered in Richmond, Virginia, is one of the nation’s largest producers and transporters of energy. Dominion’s operations are conducted through various subsidiaries, including Virginia Power, a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and North Carolina. Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into the PJM wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion. Dominion’s operations also include a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states, an LNG import and storage facility in Maryland and regulated gas transportation and distribution operations in Ohio and West Virginia. As discussed in Note 4, Dominion completed the sale of substantially all of its Appalachian E&P operations in April 2010. In addition, Dominion completed the sale of its Pennsylvania gas distribution operations in February 2010, which are reported as discontinued operations. Certain 2009 and 2008 amounts have been recast to reflect Peoples as discontinued operations. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities and retail energy marketing operations.

Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment, which includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations, which are discussed in Notes 4 and 25, respectively. 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.

NOTE 2. SIGNIFICANT ACCOUNTING POLICIES

General

Dominion and Virginia Power make certain estimates and assumptions in preparing their Consolidated Financial Statements in accordance with GAAP. These estimates and assumptions affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses for the periods presented. Actual results may differ from those estimates.

Dominion’s and Virginia Power’s Consolidated Financial Statements include, after eliminating intercompany transactions and balances, the accounts of their respective majority-owned subsidiaries.

Dominion and Virginia Power report certain contracts, instruments and investments at fair value. See Note 7 for further information on fair value measurements.

Dominion maintains pension and other postretirement benefit plans. Virginia Power participates in certain of these plans. See Note 22 for further information on these plans.

Certain amounts in the 2009 and 2008 Consolidated Financial Statements and footnotes have been reclassified to conform to the 2010 presentation for comparative purposes. The reclassifications did not affect the Companies’ net income, total assets, liabilities, shareholders’ equity or cash flows.

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

Operating Revenue

Operating revenue is recorded on the basis of services rendered, commodities delivered or contracts settled and includes amounts yet to be billed to customers. The Companies collect sales, consumption and consumer utility taxes; however, these amounts are excluded from revenue. Dominion’s customer receivables at December 31, 2010 and 2009 included $466 million and $409 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity or natural gas delivered but not yet billed to its utility customers. Virginia Power’s customer receivables at December 31, 2010 and 2009 included $397 million and $355 million, respectively, of accrued unbilled revenue based on estimated amounts of electricity delivered but not yet billed to its customers.

The primary types of sales and service activities reported as operating revenue for Dominion are as follows:

Regulated electric sales consist primarily of state-regulated retail electric sales, and federally-regulated wholesale electric sales and electric transmission services;

Nonregulated electric sales consist primarily of sales of electricity at market-based rates and contracted fixed rates, and associated derivative activity;

Regulated gas sales consist primarily of state-regulated retail natural gas sales and related distribution services;

Nonregulated gas sales consist primarily of sales of natural gas production at market-based rates and contracted fixed prices, sales of gas purchased from third parties, gas trading and marketing revenue and associated derivative activity. Revenue from sales of gas production is recognized based on actual volumes of gas sold to purchasers and is reported net of royalties. Revenue from sales of gas production includes the sale of gas produced by Dominion and the recognition of revenue from the VPP transactions described in Note 11;

Gas transportation and storage consists primarily of regulated sales of gathering, transmission, distribution and storage services and associated derivative activity. Also included are regulated gas distribution charges to retail distribution service customers opting for alternate suppliers; and

Other revenue consists primarily of sales of oil and NGL production and condensate, extracted products and associated derivative activity. Other revenue also includes miscellaneous service revenue from electric and gas distribution operations, and gas processing and handling revenue.

The primary types of sales and service activities reported as operating revenue for Virginia Power are as follows:

Regulated electric sales consist primarily of state-regulated retail electric sales and federally-regulated wholesale electric sales and electric transmission services; and

Other revenue consists primarily of excess generation sold at market-based rates, miscellaneous service revenue from electric distribution operations and other miscellaneous revenue.

Electric Fuel, Purchased Energy and Purchased Gas—Deferred Costs

Where permitted by regulatory authorities, the differences between Virginia Power’s actual electric fuel and purchased energy expenses and Dominion’s purchased gas expenses and the related levels of recovery for these expenses in current rates are deferred and matched against recoveries in future periods. The deferral of costs in excess of current period fuel rate recovery is recognized as a regulatory asset, while rate recovery in excess of current period fuel expenses is recognized as a regulatory liability.

Of the cost of fuel used in electric generation and energy purchases to serve utility customers, approximately 84% is currently subject to deferred fuel accounting, while substantially all of the remaining amount is subject to recovery through similar mechanisms.

Income Taxes

A consolidated federal income tax return is filed for Dominion and its subsidiaries, including Virginia Power. In addition, where applicable, combined income tax returns for Dominion and its subsidiaries are filed in various states; otherwise, separate state income tax returns are filed. Virginia Power participates in an intercompany tax sharing agreement with Dominion and its subsidiaries and its current income taxes are based on its taxable income or loss, determined on a separate company basis.

Accounting for income taxes involves an asset and liability approach. Deferred income tax assets and liabilities are provided, representing future effects on income taxes for temporary differences between the bases of assets and liabilities for financial reporting and tax purposes. Dominion and Virginia Power establish a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. Where the treatment of temporary differences is different for rate-regulated operations, a regulatory asset is recognized if it is probable that future revenues will be provided for the payment of deferred tax liabilities.

Dominion and Virginia Power recognize positions taken, or expected to be taken, in income tax returns that are more-likely-than-not to be realized, assuming that the position will be examined by tax authorities with full knowledge of all relevant information.

If it is not more-likely-than-not that a tax position, or some portion thereof, will be sustained, the related tax benefits are not recognized in the financial statements. For a substantial amount of Dominion’s and Virginia Power’s unrecognized tax benefits, the ultimate deductibility is highly certain; however, there is uncertainty about the timing of such deductibility. Unrecognized tax benefits may also include amounts for which uncertainty exists as to whether such amounts are deductible as ordinary deductions or capital losses. Unrecognized tax benefits may result in an increase in income taxes payable, a reduction of income tax

refunds receivable or changes in deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in income taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities. Noncurrent income taxes payable related to unrecognized tax benefits are classified in other deferred credits and other liabilities on the consolidated balance sheets and current payables are included in accrued interest, payroll and taxes on the consolidated balance sheets, except when such amounts are presented net with amounts receivable from or amounts prepaid to tax authorities.

Dominion and Virginia Power recognize changes in estimated interest payable on net underpayments and overpayments of income taxes in interest expense and estimated penalties that may result from the settlement of some uncertain tax positions in other income. In its Consolidated Statements of Income for 2010, 2009 and 2008, Dominion recognized a reduction in interest expense of $18 million and a reduction in penalties of less than $1 million, a reduction in interest expense of $19 million and a reduction in penalties of $2 million and less than $1 million of interest expense and no penalties, respectively. Dominion had accrued interest receivable of $27 million and interest and penalties payable of less than $1 million at December 31, 2010, and interest receivable of $26 million and interest and penalties payable of $4 million at December 31, 2009.

Virginia Power’s interest and penalties were immaterial in 2010, 2009 and 2008.

At December 31, 2010, Virginia Power’s Consolidated Balance Sheet included $46 million of prepaid federal and state income taxes and $102 million of noncurrent federal and state income taxes payable. At December 31, 2009, Virginia Power’s Consolidated Balance Sheet included $21 million of prepaid federal income taxes, $3 million of current state income taxes payable and $45 million of noncurrent federal and state income taxes payable.

Investment tax credits are recognized by nonregulated operations in the year qualifying property is placed in service. For regulated operations, investment tax credits are deferred and amortized over the service lives of the properties giving rise to the credits. Production tax credits are recognized as energy is generated and sold.

Cash and Cash Equivalents

Current banking arrangements generally do not require checks to be funded until they are presented for payment. At December 31, 2010 and 2009, Dominion’s accounts payable included $56 million and $55 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2010 and 2009, Virginia Power’s accounts payable included $28 million and $22 million, respectively, of checks outstanding but not yet presented for payment. For purposes of the Consolidated Statements of Cash Flows, cash and cash equivalents include cash on hand, cash in banks and temporary investments purchased with an original maturity of three months or less.

Derivative Instruments

Dominion and Virginia Power use derivative instruments such as futures, swaps, forwards, options and FTRs to manage the commodity, currency exchange and financial market risks of their business operations.

All derivatives, other than those for which an exception applies, are reported in the Consolidated Balance Sheets at fair value. Derivative contracts representing unrealized gain positions and purchased options are reported as derivative assets. Derivative contracts representing unrealized losses and options sold are reported as derivative liabilities. One of the exceptions to fair value accounting, normal purchases and normal sales, may be elected when the contract satisfies certain criteria, including a requirement that physical delivery of the underlying commodity is probable. Expenses and revenues resulting from deliveries under normal purchase contracts and normal sales contracts, respectively, are included in earnings at the time of contract performance.

Dominion and Virginia Power do not offset amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral against amounts recognized for derivative instruments executed with the same counterparty under the same master netting arrangement. Dominion had margin assets of $244 million and $149 million associated with cash collateral at December 31, 2010 and 2009, respectively. Dominion had margin liabilities of $62 million and $114 million associated with cash collateral at December 31, 2010 and 2009, respectively. Virginia Power’s margin assets and liabilities associated with cash collateral were not material at December 31, 2010 and 2009.

To manage price risk, Dominion and Virginia Power hold certain derivative instruments that are not held for trading purposes and are not designated as hedges for accounting purposes. However, to the extent the Companies do not hold offsetting positions for such derivatives, they believe these instruments represent economic hedges that mitigate their exposure to fluctuations in commodity prices, interest rates and foreign exchange rates. As part of Dominion’s strategy to market energy and manage related risks, it also manages a portfolio of commodity-based financial derivative instruments held for trading purposes. Dominion uses established policies and procedures to manage the risks associated with price fluctuations in these energy commodities and uses various derivative instruments to reduce risk by creating offsetting market positions.

Statement of Income Presentation:

Derivatives Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue on a net basis.

Derivatives Not Held for Trading Purposes: All income statement activity, including amounts realized upon settlement, is presented in operating revenue, operating expenses or interest and related charges based on the nature of the underlying risk.

In Virginia Power’s generation operations, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities for jurisdictions subject to cost-based rate regulation. Realized gains or losses on the derivative instruments are generally recognized when the related transactions impact earnings.

DERIVATIVE INSTRUMENTS DESIGNATED AS HEDGING INSTRUMENTS

Dominion and Virginia Power designate a portion of their derivative instruments as either cash flow or fair value hedges for accounting purposes. For all derivatives designated as hedges, Dominion and Virginia Power formally document the relation-

ship between the hedging instrument and the hedged item, as well as the risk management objective and the strategy for using the hedging instrument. The Companies assess whether the hedging relationship between the derivative and the hedged item is highly effective at offsetting changes in cash flows or fair values both at the inception of the hedging relationship and on an ongoing basis. Any change in the fair value of the derivative that is not effective at offsetting changes in the cash flows or fair values of the hedged item is recognized currently in earnings. Also, the Companies may elect to exclude certain gains or losses on hedging instruments from the assessment of hedge effectiveness, such as gains or losses attributable to changes in the time value of options or changes in the difference between spot prices and forward prices, thus requiring that such changes be recorded currently in earnings. Hedge accounting is discontinued prospectively for derivatives that cease to be highly effective hedges.

Cash Flow Hedges—A majority of Dominion’s and Virginia Power’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase and sale of electricity, natural gas and other energy-related products. The Companies also use foreign currency contracts to hedge the variability in foreign exchange rates and interest rate swaps to hedge their exposure to variable interest rates on long-term debt. For transactions in which Dominion and Virginia Power are hedging the variability of cash flows, changes in the fair value of the derivatives are reported in AOCI, to the extent they are effective at offsetting changes in the hedged item. Any derivative gains or losses reported in AOCI are reclassified to earnings when the forecasted item is included in earnings, or earlier, if it becomes probable that the forecasted transaction will not occur. For cash flow hedge transactions, hedge accounting is discontinued if the occurrence of the forecasted transaction is no longer probable.

Fair Value Hedges—Dominion and Virginia Power also use fair value hedges to mitigate the fixed price exposure inherent in certain firm commodity commitments and commodity inventory. In addition, they have designated interest rate swaps as fair value hedges on certain fixed-rate long-term debt to manage interest rate exposure. For fair value hedge transactions, changes in the fair value of the derivative are generally offset currently in earnings by the recognition of changes in the hedged item’s fair value. Derivative gains and losses from the hedged item are reclassified to earnings when the hedged item is included in earnings, or earlier, if the hedged item no longer qualifies for hedge accounting. Hedge accounting is discontinued if the hedged item no longer qualifies for hedge accounting.

See Note 7 for further information about fair value measurements and associated valuation methods for derivatives. See Note 8 for further information on derivatives.

Property, Plant and Equipment

Property, plant and equipment, including additions and replacements is recorded at original cost, consisting of labor and materials and other direct and indirect costs such as asset retirement costs, capitalized interest and, for certain operations subject to cost-of-service rate regulation, AFUDC and overhead costs. The cost of repairs and maintenance, including minor additions and replacements, is charged to expense as it is incurred.

In 2010, 2009 and 2008, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $102 million, $76 million and $88 million, respectively. In 2010, 2009 and

2008, Virginia Power capitalized interest costs and AFUDC to property, plant and equipment of $61 million, $47 million and $21 million, respectively. Under current Virginia legislation, certain Virginia jurisdictional projects qualify for current recovery of AFUDC through rate adjustment clauses. AFUDC on these projects is calculated and recorded as a regulatory asset and is not capitalized to property, plant and equipment. In 2010, 2009 and 2008, Virginia Power recorded $13 million, $34 million and $18 million of AFUDC related to these projects, respectively.

For Virginia Power property subject to cost-of-service rate regulation, including electric distribution, electric transmission, and generation property and for certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is generally charged to accumulated depreciation at retirement, with gains and losses recorded on the sales of property. Cost of removal collections from utility customers not representing AROs are recorded as regulatory liabilities.

For Dominion and Virginia Power property that is not subject to cost-of-service rate regulation, including nonutility property, cost of removal not associated with AROs is charged to expense as incurred. The Companies also record gains and losses upon retirement based upon the difference between the proceeds received, if any, and the property’s net book value at the retirement date.

Depreciation of property, plant and equipment is computed on the straight-line method based on projected service lives. Dominion’s and Virginia Power’s depreciation rates on utility property, plant and equipment are as follows:


Year Ended December 31,	2010		2009		2008
(percent)
Dominion
Generation		2.59		2.62		2.60
Transmission		2.24		2.27		2.22
Distribution		3.20		3.21		3.22
Storage		2.75		2.83		2.87
Gas gathering and processing		2.39		2.18		2.13
General and other		4.60		4.33		4.35

Virginia Power
Generation		2.59		2.62		2.60
Transmission		1.94		1.92		2.03
Distribution		3.33		3.33		3.37
General and other		4.28		3.95		3.97

Dominion’s nonutility property, plant and equipment, excluding E&P properties, is depreciated using the straight-line method over the following estimated useful lives:


Asset	Estimated Useful Lives
Merchant generation—nuclear		29–44 years
Merchant generation—other		8–40 years
General and other		3–25 years

Nuclear fuel used in electric generation is amortized over its estimated service life on a units-of-production basis. Dominion and Virginia Power report the amortization of nuclear fuel in electric fuel and other energy-related purchases expense in their Consolidated Statements of Income and in depreciation and amortization in their Consolidated Statements of Cash Flows.

Dominion follows the full cost method of accounting for its gas and oil E&P activities, which subjects capitalized costs to a

quarterly ceiling test using hedge-adjusted prices. Due to the April 2010 sale of substantially all of its Appalachian E&P operations, as of December 31, 2010, Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

At March 31, 2010, Dominion recorded a ceiling test impairment charge of $21 million ($13 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income primarily due to a decline in hedge-adjusted prices reflecting the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 4.

In 2009, Dominion recorded a ceiling test impairment charge of $455 million ($281 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income. Excluding the effects of hedge-adjusted prices in calculating the ceiling limitation, the impairment would have been $631 million ($387 million after-tax).

In 2010, Dominion recognized a gain from the sale of substantially all of its Appalachian E&P operations as discussed in Note 4.

Emissions Allowances

Emissions allowances permit the holder of the allowance to emit certain gaseous by-products of fossil fuel combustion, including SO₂, NO_X and CO₂. SO₂ and NO_X emissions allowances are issued to Dominion and Virginia Power by the EPA and may also be purchased and sold via third party contracts. CO₂ emissions allowances are available for purchase by Dominion through quarterly auctions held by participating RGGI states. The first RGGI auctions of CO₂ allowances were conducted in 2008 to be used for the compliance period beginning in 2009 and extending through 2011. Compliance with the RGGI requirements only applies to certain of Dominion’s merchant power stations located in the Northeast.

Allowances held may be transacted with third parties or consumed as these emissions are generated. Allowances allocated to or acquired by the Companies’ generation operations are held primarily for consumption.

Allowances held for consumption are classified as intangible assets in the Consolidated Balance Sheets. Carrying amounts are based on the cost to acquire the allowances or, in the case of a business combination, on the fair values assigned to them in the allocation of the purchase price of the acquired business. A portion of Dominion’s and Virginia Power’s SO₂ and NO_X allowances are issued by the EPA at zero cost.

These allowances are amortized in the periods the emissions are generated, with the amortization reflected in DD&A in the Consolidated Statements of Income. Purchases and sales of these allowances are reported as investing activities in the Consolidated Statements of Cash Flows and gains or losses resulting from sales are reported in other operations and maintenance expense in the Consolidated Statements of Income.

Long-Lived and Intangible Assets

Dominion and Virginia Power perform an evaluation for impairment whenever events or changes in circumstances indicate that the carrying amount of long-lived assets or intangible assets with finite lives may not be recoverable. A long-lived or intangible asset is written down to fair value if the sum of its expected future undiscounted cash flows is less than its carrying amount.

Intangible assets with finite lives are amortized over their estimated useful lives. See Note 7 for a discussion of impairments related to certain long-lived assets.

Regulatory Assets and Liabilities

The accounting for Dominion’s regulated gas and Virginia Power’s regulated electric operations differs from the accounting for nonregulated operations in that they are required to reflect the effect of rate regulation in their Consolidated Financial Statements. For regulated businesses subject to federal or state cost-of-service rate regulation, regulatory practices that assign costs to accounting periods may differ from accounting methods generally applied by nonregulated companies. When it is probable that regulators will permit the recovery of current costs through future rates charged to customers, these costs that otherwise would be expensed by nonregulated companies are deferred as regulatory assets. Likewise, regulatory liabilities are recognized when it is probable that regulators will require customer refunds through future rates or when revenue is collected from customers for expenditures that have yet to be incurred. Generally, regulatory assets and liabilities are amortized into income over the period authorized by the regulator.

Asset Retirement Obligations

Dominion and Virginia Power recognize AROs at fair value as incurred or when sufficient information becomes available to determine a reasonable estimate of the fair value of future retirement activities to be performed. These amounts are capitalized as costs of the related tangible long-lived assets. Since relevant market information is not available, fair value is estimated using discounted cash flow analyses. Virginia Power reports accretion of the AROs associated with nuclear decommissioning of its nuclear power stations due to the passage of time as an adjustment to the related regulatory liability for certain jurisdictions, consistent with the practice for its other cost-of-service rate regulated operations. Dominion and Virginia Power report accretion of all other AROs in other operations and maintenance expense in the Consolidated Statements of Income.

Amortization of Debt Issuance Costs

Dominion and Virginia Power defer and amortize debt issuance costs and debt premiums or discounts over the expected lives of the respective debt issues, considering maturity dates and, if applicable, redemption rights held by others. As permitted by regulatory authorities, gains or losses resulting from the refinancing of debt allocable to utility operations subject to cost-based rate regulation have also been deferred and are amortized over the lives of the new issuances.

Investments

MARKETABLE EQUITY AND DEBT SECURITIES

Dominion accounts for and classifies investments in marketable equity and debt securities as trading or available-for-sale securities. Virginia Power classifies investments in marketable equity and debt securities as available-for-sale securities.

Trading securities include marketable equity and debt securities held by Dominion in rabbi trusts associated with certain deferred compensation plans. These securities are reported in other investments in the Consolidated Balance Sheets at fair

value with net realized and unrealized gains and losses included in other income in the Consolidated Statements of Income.

Available-for-sale securities include all other marketable equity and debt securities, primarily comprised of securities held in the nuclear decommissioning trusts. These investments are reported at fair value in nuclear decommissioning trust funds in the Consolidated Balance Sheets. Net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in Virginia Power’s nuclear decommissioning trusts are recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation. For all other available-for-sale securities, including those held in Dominion’s merchant generation nuclear decommissioning trusts, net realized gains and losses (including any other-than-temporary impairments) are included in other income and unrealized gains and losses are reported as a component of AOCI, net of tax.

In determining realized gains and losses for marketable equity and debt securities, the cost basis of the security is based on the specific identification method.

NON-MARKETABLE INVESTMENTS

Dominion and Virginia Power account for illiquid and privately held securities for which market prices or quotations are not readily available under either the equity or cost method. Non-marketable investments include:

Equity method investments when Dominion and Virginia Power have the ability to exercise significant influence, but not control, over the investee. Dominion’s investments are included in investments in equity method affiliates and Virginia Power’s investments are included in other investments in their Consolidated Balance Sheets. Dominion and Virginia Power record equity method adjustments in other income in the Consolidated Statements of Income including: their proportionate share of investee income or loss, gains or losses resulting from investee capital transactions, amortization of certain differences between the carrying value and the equity in the net assets of the investee at the date of investment and other adjustments required by the equity method.

Cost method investments when Dominion and Virginia Power do not have the ability to exercise significant influence over the investee. Dominion’s and Virginia Power’s investments are included in other investments and nuclear decommissioning trust funds.

OTHER-THAN-TEMPORARY IMPAIRMENT

Dominion and Virginia Power periodically review their investments to determine whether a decline in fair value should be considered other than temporary. If a decline in fair value of any security is determined to be other than temporary, the security is written down to its fair value at the end of the reporting period.

Decommissioning Trust Investments—Special Considerations

Debt Securities—The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which Dominion and Virginia Power adopted effective April 1, 2009. The recognition provisions of this

guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, Dominion and Virginia Power considered all debt securities held by their nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as they did not have the ability to ensure the investments were held through the anticipated recovery period.

Effective with the adoption of this guidance, using information obtained from their nuclear decommissioning trust fixed-income investment managers, Dominion and Virginia Power record in earnings any unrealized loss for a debt security when the manager intends to sell the debt security or it is more-likely-than-not that the manager will have to sell the debt security before recovery of its fair value up to its cost basis. If that is the case, but the debt security is deemed to have experienced a credit loss, the Companies record the credit loss in earnings and any remaining portion of the unrealized loss in other comprehensive income. Credit losses are evaluated primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors.

Equity securities and other investments—Dominion’s and Virginia Power’s method of assessing other-than-temporary declines requires demonstrating the ability to hold individual securities for a period of time sufficient to allow for the anticipated recovery in their market value prior to the consideration of the other criteria mentioned above. Since the Companies have limited ability to oversee the day-to-day management of nuclear decommissioning trust fund investments, they do not have the ability to ensure investments are held through an anticipated recovery period. Accordingly, they consider all equity and other securities as well as non-marketable investments held in nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired.

Inventories

Materials and supplies and fossil fuel inventories are valued primarily using the weighted-average cost method. Stored gas inventory used in Dominion’s Ohio gas distribution operations is valued using the LIFO method. Under the LIFO method, stored gas inventory was valued at $48 million and $30 million at December 31, 2010 and 2009, respectively. Based on the average price of gas purchased during 2010 and 2009, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $107 million and $172 million, respectively. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method.

Gas Imbalances

Natural gas imbalances occur when the physical amount of natural gas delivered from, or received by, a pipeline system or storage facility differs from the contractual amount of natural gas delivered or received. Dominion values these imbalances due to, or from, shippers and operators at an appropriate index price at period end, subject to the terms of its tariff for regulated entities.

Imbalances are primarily settled in-kind. Imbalances due to Dominion from other parties are reported in other current assets and imbalances that Dominion owes to other parties are reported in other current liabilities in the Consolidated Balance Sheets.

Goodwill

Dominion evaluates goodwill for impairment annually as of April 1 and whenever an event occurs or circumstances change in the interim that would more-likely-than-not reduce the fair value of a reporting unit below its carrying amount.

NOTE 3. NEWLY ADOPTED ACCOUNTING STANDARDS

2009

NONCONTROLLING INTERESTS IN CONSOLIDATED FINANCIAL STATEMENTS

Effective January 1, 2009, Dominion adopted new accounting guidance for noncontrolling interests that requires retrospective application of presentation and disclosure changes including that noncontrolling interests be reported as a component of equity and that net income attributable to the parent and noncontrolling interests be separately identified in the income statement.

As discussed in Note 25, Dominion previously consolidated an investment in the subordinated notes of a third-party CDO entity held by DCI, which was deconsolidated as of March 31, 2008. The noncontrolling interest income from the CDO entity was previously reported in minority interest in Dominion’s Consolidated Statements of Income and in operating activities in its Consolidated Statements of Cash Flows. Dominion’s subsidiary preferred dividends were previously included in interest and related charges in its Consolidated Statements of Income and in operating activities in its Consolidated Statements of Cash Flows. Due to the application of new accounting guidance for noncontrolling interests, Dominion now reflects its interest in the previously held CDO entity’s income and its subsidiary preferred dividends as an adjustment (noncontrolling interests) to arrive at net income attributable to Dominion in its Consolidated Statements of Income and reflects its subsidiary preferred dividends in financing activities in its Consolidated Statements of Cash Flows. Since Dominion’s subsidiary preferred stock does not qualify as permanent equity, Dominion continues to report these amounts as mezzanine equity in its Consolidated Balance Sheets.

RECOGNITION AND PRESENTATION OF OTHER-THAN-TEMPORARY IMPAIRMENTS

The FASB amended its guidance for the recognition and presentation of other-than-temporary impairments, which Dominion and Virginia Power adopted effective April 1, 2009. The recognition provisions of this guidance apply only to debt securities classified as available-for-sale or held-to-maturity, while the presentation and disclosure requirements apply to both debt and equity securities. Prior to the adoption of this guidance, as described in Note 2, the Companies considered all debt securities held by their nuclear decommissioning trusts with market values below their cost bases to be other-than-temporarily impaired as they did not have the ability to ensure the investments were held through the anticipated recovery period.

Upon the adoption of this guidance for debt investments held at April 1, 2009, Dominion recorded a $20 million ($12 million after-tax) and Virginia Power recorded a $3 million ($2 million after-tax) cumulative effect of a change in accounting principle to reclassify the non-credit related portion of previously recognized other-than-temporary impairments from retained earnings to AOCI, reflecting the fixed-income investment managers’ intent and ability to hold the debt securities until recovery of their fair values up to their cost bases.

SEC FINAL RULE, MODERNIZATION OF OIL AND GAS REPORTING

Effective December 31, 2009, Dominion adopted the SEC Final Rule, Modernization of Oil and Gas Reporting, which revised the existing Regulation S-K and Regulation S-X reporting requirements. Under the new requirements, the ceiling test is calculated using an average price based on the prior 12-month period rather than period-end prices. Due to the April 2010 sale of substantially all of its Appalachian E&P operations, as of December 31, 2010 Dominion no longer has any significant gas and oil properties subject to the ceiling test calculation.

2008

FAIR VALUE MEASUREMENTS

Dominion and Virginia Power adopted new FASB guidance effective January 1, 2008, which defines fair value, establishes a framework for measuring fair value and expands disclosures related to fair value measurements. The guidance applies broadly to financial and non-financial assets and liabilities that are measured at fair value under other authoritative accounting pronouncements, but does not expand the application of fair value accounting to any new circumstances.

Generally, the provisions of this guidance were applied prospectively. Certain situations, however, required retrospective application as of the beginning of the year of adoption through the recognition of a cumulative effect of accounting change. Such retrospective application was required for financial instruments, including derivatives and certain hybrid instruments with limitations on initial gains or losses. Retrospective application resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008 for Dominion and no adjustment for Virginia Power.

See Note 7 for further information on fair value measurements.

ENDORSEMENT SPLIT-DOLLAR LIFE INSURANCE ARRANGEMENTS

Effective January 1, 2008, Dominion adopted new accounting guidance for deferred compensation and postretirement benefit aspects of endorsement split-dollar life insurance arrangements. This guidance specifies that if an employer provides a benefit to an employee under the endorsement split-dollar life insurance arrangement that extends to post-retirement periods, it should recognize a liability for future benefits based on the substantive agreement with the employee. Dominion’s adoption of this guid-

ance resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008.

NOTE 4. DISPOSITIONS

Sale of Appalachian E&P Operations

In April 2010, Dominion completed the sale of substantially all of its Appalachian E&P operations to a newly-formed subsidiary of CONSOL for approximately $3.5 billion. The transaction includes the mineral rights to approximately 491,000 acres in the Marcellus Shale formation. Dominion retained certain oil and natural gas wells located on or near its natural gas storage fields. The transaction generated after-tax proceeds of approximately $2.2 billion and resulted in an after-tax gain of approximately $1.4 billion, which includes a $134 million write-off of goodwill. Proceeds from the sale have been or will be used to pay taxes on the gain, offset all of Dominion’s equity needs for 2010 and its expected market equity issuance needs for 2011, repurchase common stock, fund contributions to Dominion’s pension plans and the Dominion Foundation, reduce debt and offset the majority of the impact of Virginia Power’s 2009 base rate case settlement.

The results of operations for Dominion’s Appalachian E&P business are not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool.

Due to the sale, hedge accounting was discontinued for certain cash flow hedges since it became probable that the forecasted sales of gas would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a $42 million ($25 million after-tax) benefit, recorded in operating revenue in its Consolidated Statement of Income, reflecting the reclassification of gains from AOCI to earnings for these contracts in March 2010.

Sale of Peoples

In February 2010, Dominion completed the sale of Peoples to PNG Companies LLC and netted after-tax proceeds of approximately $542 million. The sale resulted in an after-tax loss of approximately $140 million, including post-closing adjustments, and a $79 million write-off of goodwill. The sale also resulted in after-tax expenses of approximately $27 million, including transaction and benefit-related costs. Prior to the sale, Peoples had income from operations of $12 million after-tax during 2010.

Prior to March 31, 2010, Dominion did not report Peoples as discontinued operations since it expected to have significant continuing cash flows related primarily to the sale of natural gas production from its Appalachian E&P operations to Peoples. Due to the sale of its Appalachian E&P operations, Dominion will not have significant continuing cash flows with Peoples; therefore, the results of Peoples were reclassified to discontinued operations in the Consolidated Statements of Income for all periods presented. Certain 2009 and 2008 amounts have been recast to reflect Peoples as discontinued operations.

The carrying amounts of the major classes of assets and liabilities classified as held for sale in Dominion’s Consolidated Balance Sheets were as follows:


At December 31,	2009
(millions)
ASSETS
Current Assets
Customer receivables	$	87
Other		56
Total current assets		143
Property, Plant and Equipment
Property, plant and equipment		985
Accumulated depreciation, depletion and amortization		(284	)
Total property, plant and equipment, net		701
Deferred Charges and Other Assets
Regulatory assets		125
Other		49
Total deferred charges and other assets		174
Assets held for sale	$	1,018
LIABILITIES
Current Liabilities	$	133
Deferred Credits and Other Liabilities
Deferred income taxes and investment tax credits		238
Other		57
Total deferred credits and other liabilities		295
Liabilities held for sale	$	428

The following table presents selected information regarding the results of operations of Peoples, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income:


Year Ended December 31,	2010			2009		2008
(millions)
Operating revenue	$	67		$	432	$	535
Income (loss) before income taxes⁽¹⁾		(134	)⁽²⁾		42		119

(1)

The year ended December 31, 2008 includes a $47 million benefit related to the re-establishment of certain regulatory assets expected to be recovered through future rates under the terms of the sale agreement. The year ended December 31, 2009 includes the impact of a $22 million charge due to a reduction of the previously established regulatory asset.

(2)

Includes a loss and other charges related to the sale of Peoples.

NOTE 5. OPERATING REVENUE

Dominion’s and Virginia Power’s operating revenue consists of the following:


Year Ended December 31,	2010		2009		2008
(millions)
Dominion
Electric sales:
Regulated	$	7,123	$	6,477	$	6,797
Nonregulated		3,829		3,802		3,543
Gas sales:
Regulated		308		494		877
Nonregulated		2,010		2,315		3,114
Gas transportation and storage		1,493		1,268		1,072
Other		434		442		492
Total operating revenue	$	15,197	$	14,798	$	15,895
Virginia Power
Regulated electric sales	$	7,123	$	6,477	$	6,797
Other		96		107		137
Total operating revenue	$	7,219	$	6,584	$	6,934

NOTE 6. INCOME TAXES

Judgment and the use of estimates are required in developing the provision for income taxes and reporting of tax-related assets and liabilities. The interpretation of tax laws involves uncertainty, since tax authorities may interpret the laws differently. Dominion and Virginia Power are routinely audited by federal and state tax authorities. Ultimate resolution of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

In 2010, U.S. federal legislation was enacted that allows taxpayers to fully deduct qualifying capital expenditures incurred after September 8, 2010, through the end of 2011, when placed in service before 2013, and otherwise provides an extension of the fifty percent bonus depreciation allowance for qualifying capital expenditures through 2012. However, there is uncertainty about the earliest date on which construction of property by or for a taxpayer could have begun in order to qualify for the full deduction of qualifying capital expenditures. Clarifying guidance is expected from the U.S. Treasury Department in 2011. For Dominion and Virginia Power, income taxes payable have been reduced and deferred tax liabilities have increased in 2010 as a result of claiming these benefits.

Continuing Operations

Details of income tax expense for continuing operations including noncontrolling interests were as follows:


	Dominion									Virginia Power
Year Ended December 31,	2010			2009			2008			2010			2009			2008
(millions)
Current:
Federal	$	891		$	952		$	502		$	(78	)	$	465		$	158
State		308			129			115			10			91			37
Total current		1,199			1,081			617			(68	)		556			195
Deferred:
Federal		764			(424	)		338			537			(339	)		279
State		96			(59	)		3			74			(69	)		30
Total deferred		860			(483	)		341			611			(408	)		309
Amortization of deferred investment tax credits		(2	)		(2	)		(5	)		(1	)		(1	)		(4	)
Total income tax expense	$	2,057		$	596		$	953		$	542		$	147		$	500

For continuing operations including noncontrolling interests, the statutory U.S. federal income tax rate reconciles to Dominion’s and Virginia Power’s effective income tax rate as follows:


	Dominion									Virginia Power
Year Ended December 31,	2010			2009			2008			2010			2009			2008
U.S. statutory rate		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%		35.0	%
Increases (reductions) resulting from:
Goodwill—sale of U.S. Appalachian E&P business		0.9			—			—			—			—			—
Legislative change		1.1			0.4			(0.1	)		1.1			—			(0.4	)
State taxes, net of federal benefit		5.0			2.4			2.5			3.8			2.8			3.6
Valuation allowances		0.1			(0.4	)		0.5			—			—			—
Domestic production activities deduction		(0.4	)		(2.9	)		(0.5	)		(0.3	)		(4.5	)		(0.5	)
Investment and production tax credits		(0.3	)		(1.5	)		(0.1	)		—			(0.2	)		(0.1	)
Amortization of investment tax credits		—			(0.1	)		(0.2	)		(0.1	)		(0.2	)		(0.3	)
AFUDC – equity		(0.4	)		(1.0	)		(0.3	)		(1.1	)		(3.4	)		(0.5	)
Employee stock ownership plan deduction		(0.3	)		(0.8	)		(0.5	)		—			—			—
Pension and other benefits		—			(0.6	)		(0.3	)		—			(0.6	)		(0.2	)
Other, net		0.1			1.3			0.5			0.5			0.4			0.1
Effective tax rate		40.8	%		31.8	%		36.5	%		38.9	%		29.3	%		36.7	%

Dominion’s and Virginia Power’s effective tax rates in 2010 reflect reductions of deferred tax assets of $57 million and $17 million, respectively, resulting from the enactment of the Patient Protection and Affordable Care Act and the Health Care and Education Affordability Reconciliation Act of 2010, which eliminated the employer’s deduction, beginning in 2013, for that portion of its retiree prescription drug coverage cost that is being reimbursed by the Medicare Part D subsidy. In addition, Dominion’s effective tax rate in 2010 includes higher state income taxes and the impact of goodwill written off that is not deductible for tax purposes associated with the sale of the Appalachian E&P operations.

Dominion’s and Virginia Power’s effective tax rates in 2009 reflect the reduction of uncertainties regarding the calculation of the domestic production activities deduction as a result of working with the IRS under its Pre-Filing Program. The objective of the Pre-Filing Program is to provide taxpayers with greater certainty regarding a specific issue at an earlier point in time than can be attained under the normal post-filing examination process.

Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

The Companies’ deferred income taxes consist of the following:


	Dominion						Virginia Power
At December 31,	2010			2009			2010			2009
(millions)
Deferred income taxes:
Total deferred income tax assets	$	1,642		$	1,839		$	402		$	533
Total deferred income tax liabilities		6,233			5,683			3,139			2,652
Total net deferred income tax liabilities	$	4,591		$	3,844		$	2,737		$	2,119
Total deferred income taxes:
Plant and equipment, primarily depreciation method and basis differences	$	3,027		$	2,877		$	2,109		$	1,934
Nuclear decommissioning		749			689			343			307
Deferred state income taxes		446			416			228			152
Deferred fuel, purchased energy and gas costs		120			12			111			7
Pension benefits		521			351			26			(49	)
Other postretirement benefits		(186	)		(216	)		(14	)		(29	)
Loss and credit carryforwards		(181	)		(192	)		—			—
Reserve for rate proceedings		(56	)		(179	)		(56	)		(179	)
Partnership basis differences		265			236			—			—
Valuation allowances		68			62			—			—
Other		(182	)		(212	)		(10	)		(24	)
Total net deferred income tax liabilities	$	4,591		$	3,844		$	2,737		$	2,119

At December 31, 2010, Dominion had the following loss and credit carryforwards:

Federal loss carryforwards of $38 million that expire if unutilized during the period 2014 through 2021;

State loss carryforwards of $840 million that expire if unutilized during the period 2011 through 2030. A valuation allowance on $701 million of these carryforwards has been established; and

State minimum tax credits of $94 million that do not expire.

There were no loss or credit carryforwards for Virginia Power at December 31, 2010.

Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely-than-not recognition threshold, assuming that the position will be examined by tax authorities with full knowledge of all relevant information. The amount of tax return positions that are not recognized in the financial statements is disclosed as unrecognized tax benefits. These unrecognized tax benefits may impact the

financial statements by increasing income taxes payable, reducing tax refunds receivable or changing deferred taxes. Also, when uncertainty about the deductibility of an amount is limited to the timing of such deductibility, the increase in taxes payable (or reduction in tax refunds receivable) is accompanied by a decrease in deferred tax liabilities.

A reconciliation of changes in the Companies’ unrecognized tax benefits follows:


	Dominion									Virginia Power
	2010			2009			2008			2010			2009			2008
(millions)
Balance at January 1	$	291		$	404		$	407		$	121		$	180		$	195
Increases—prior period positions		34			51			42			4			11			20
Decreases—prior period positions		(59	)		(142	)		(54	)		(28	)		(71	)		(22	)
Current period positions		61			43			63			25			22			20
Prior period positions becoming otherwise deductible in current period		(16	)		(36	)		(21	)		(5	)		(9	)		(11	)
Settlements with tax authorities		—			(13	)		(33	)		—			(9	)		(22	)
Expiration of statutes of limitation		(4	)		(16	)		—			—			(3	)		—
Balance at December 31	$	307		$	291		$	404		$	117		$	121		$	180

Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits may result from claims for tax benefits, or portions thereof, that may not be realized, remeasurement of amounts expected to be realized, settlements with tax authorities and expiration of statutes of limitation. For Dominion and its subsidiaries, these unrecognized tax benefits were $133 million, $95 million and $121 million at December 31, 2010, 2009 and 2008, respectively. For Dominion, the change in these unrecognized tax benefits increased income tax expense by $38 million in 2010, decreased income tax expense by $26 million in 2009 and increased tax expense by $25 million in 2008. For Virginia Power, these unrecognized tax benefits were $14 million, $14 million and $21 million at December 31, 2010, 2009 and 2008, respectively. For Virginia Power, the change in these unrecognized tax benefits increased income tax expense by less than $1 million in 2010, decreased income tax expense by $7 million in 2009 and increased income tax expense by $13 million in 2008.

A substantial amount of Dominion’s and Virginia Power’s unrecognized tax benefits balances at December 31, 2010 represents tax positions for which the ultimate deductibility is highly certain; however, there is uncertainty about the timing of such deductibility. When uncertainty about the deductibility of amounts is limited to the timing of such deductibility, any tax liabilities recognized for prior periods would be subject to offset with the availability of refundable amounts from later periods when such deductions could otherwise be taken. Some prior year unrecognized tax benefits had involved uncertainty as to whether the amounts were deductible as ordinary deductions or capital losses. Pending resolution of these uncertainties, interest is accrued until the period in which the amounts would become deductible.

For Dominion and its subsidiaries, the U.S. federal statute of limitations has expired for years prior to 2004, except that the right to pursue refunds related to certain deductions has been reserved for the years 1995 through 2003.

In 2010, the IRS began its examination of Dominion’s consolidated tax returns for tax years 2006 and 2007, and Dominion began settlement negotiations with the Appellate Division of the IRS regarding adjustments proposed in the examination of its consolidated tax returns for 2004 and 2005. Other than two tax positions for which Dominion will reserve the right to litigate and pursue claims for refunds, Dominion and the IRS have agreed on the resolution of the issues for 2004 and 2005. The settlement is subject to review by the Joint Committee.

In September 2010, the Appellate Division of the IRS informed Dominion that the Joint Committee had approved the settlement of tax years 2002 and 2003 for Dominion and its consolidated subsidiaries. Dominion received a refund of $54 million in November 2010. The settlement excludes two issues, for which Dominion has reserved the right to litigate and pursue claims for refunds.

In 2009, the Joint Committee completed its review of Dominion’s settlement with the Appellate Division of the IRS for tax years 1999 through 2001. Dominion was entitled to a $60 million refund, of which $20 million was applied as an estimated payment for 2009 taxes and $40 million was paid to Dominion in October 2009. In addition, Dominion received a $5 million refund for 1998 due to loss carryback adjustments. Virginia Power was entitled to a $39 million refund, of which $20 million was applied as an estimated payment for 2009 taxes and $19 million was paid to Virginia Power in October 2009. The refunds had no impact on earnings.

During examinations by tax authorities in 2011, it is reasonably possible that Dominion and tax authorities could agree to apply procedures used previously to resolve similar tax return filing positions, reducing Dominion’s unrecognized tax benefits by $50 million to $70 million and Virginia Power’s unrecognized tax benefits by $30 million to $35 million. Dominion’s unrecognized tax benefits could also be reduced by $15 million, including $5 million for Virginia Power, to recognize prior period amounts becoming otherwise deductible in 2011. If such changes were to occur, other than revisions of the accrual for interest on tax underpayments and overpayments, Dominion’s earnings could increase by up to $25 million with no material impact on Virginia Power’s earnings.

Otherwise, with regard to 2010 and prior years, Dominion and Virginia Power cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2011.

For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:


State	Earliest Open Tax Year
Pennsylvania		2007
Connecticut		2007
Massachusetts		2007
Virginia⁽¹⁾		2007
West Virginia		2007

(1)

Virginia is the only state considered major for Virginia Power’s operations.

Dominion and Virginia Power are also obligated to report adjustments resulting from IRS settlements to state tax authorities. In addition, if Dominion utilizes state net operating losses or tax credits generated in years for which the statute of limitations has expired, such amounts are subject to examination.

Discontinued Operations

Income tax expense in 2010 for Dominion’s discontinued operations primarily reflects the impact of goodwill written off in the sale of Peoples that is not deductible for tax purposes and the reversal of deferred taxes for which the benefit was offset by the reversal of income tax-related regulatory assets.

Income tax expense in 2008 for Dominion’s discontinued operations reflects the reversal of $120 million of deferred tax liabilities recognized in 2006, associated with the excess of its financial reporting basis over the tax basis in the stock of Peoples. In 2006, based on the terms of a previous agreement to sell Peoples, Dominion recognized these deferred tax liabilities since the difference between the financial reporting basis and its tax basis in the stock of the subsidiaries was expected to reverse upon closing of the sale. In January 2008, Dominion agreed to terminate the agreement for the sale of Peoples and Hope. At that time, based on its expectation that the form of any future disposal of these subsidiaries would be structured so that the taxable gain would instead be determined by reference to the basis in the subsidiaries’ underlying assets, Dominion reversed the related deferred tax liabilities recognized in 2006. Dominion executed a new agreement in July 2008 to sell Peoples and Hope, but decided in December 2009 to sell only Peoples. Dominion determined its taxable gain by reference to the basis in the subsidiary’s underlying assets.

NOTE 7. FAIR VALUE MEASUREMENTS

As described in Note 3, Dominion and Virginia Power adopted new FASB guidance for fair value measurements effective January 1, 2008. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (exit price) in an orderly transaction between market participants at the measurement date. However, the use of a mid-market pricing convention (the mid-point between bid and ask prices) is permitted. Fair values are based on assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and the risks inherent in valuation techniques and the inputs to valuations. This includes not only the credit standing of counterparties involved and the impact of credit enhancements but also the impact of Dominion’s and Virginia Power’s own nonperformance risk on their liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability (the market with the most volume and activity for the asset or liability from the perspective of the reporting entity), or in the absence of a principal market, the most advantageous market for the asset or liability (the market in which the reporting entity would be able to maximize the amount received or minimize the amount paid). Dominion and Virginia Power apply fair value measurements to certain assets and liabilities including commodity and interest rate derivative instruments, and nuclear decommissioning trust and other investments including those held in Dominion’s rabbi, pension

and other postretirement benefit plan trusts, in accordance with the requirements described above. The Companies apply credit adjustments to their derivative fair values in accordance with the requirements described above. These credit adjustments are currently not material to the derivative fair values.

The Companies maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, they seek price information from external sources, including broker quotes and industry publications. When evaluating pricing information provided by brokers and other pricing services, they consider whether the broker is willing and able to trade at the quoted price, if the broker quotes are based on an active market or an inactive market and the extent to which brokers are utilizing a particular model if pricing is not readily available. If pricing information from external sources is not available, or if the Companies believe that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases they must estimate prices based on available historical and near-term future price information and certain statistical methods, including regression analysis, that reflect their market assumptions.

For options and contracts with option-like characteristics where observable pricing information is not available from external sources, the Companies generally use a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions when estimating fair value. The Companies use other option models under special circumstances, including a Spread Approximation Model when contracts include different commodities or commodity locations and a Swing Option Model when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, the Companies may estimate fair value using a discounted cash flow approach deemed appropriate in the circumstances and applied consistently from period to period. For individual contracts, the use of different valuation models or assumptions could have a significant effect on the contract’s estimated fair value.

The inputs and assumptions used in measuring fair value include the following:

For commodity and foreign currency derivative contracts:

Forward commodity prices

Forward foreign currency prices

Price volatility

Volumes

Commodity location

Interest rates

Credit quality of counterparties and Dominion and Virginia Power

Credit enhancements

Time value

For interest rate derivative contracts:

Interest rate curves

Credit quality of counterparties and Dominion and Virginia Power

Credit enhancements

Time value

For investments:

Quoted securities prices

Securities trading information including volume and restrictions

Maturity

Interest rates

Credit quality

NAV (only for alternative investments)

Dominion and Virginia Power regularly evaluate and validate the inputs used to estimate fair value by a number of methods, including review and verification of models, as well as various market price verification procedures such as the use of pricing services and multiple broker quotes to support the market price of the various commodities and investments in which the Companies transact.

The Companies also utilize the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value, into three broad levels:

Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that they have the ability to access at the measurement date. Instruments categorized in Level 1 primarily consist of financial instruments such as the majority of exchange-traded derivatives, and exchange-listed equities, mutual funds and certain Treasury securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter commodity forwards and swaps, interest rate swaps, foreign currency forwards and options, certain Treasury securities, money market funds, and corporate, state and municipal debt securities held in nuclear decommissioning trust funds for Dominion and Virginia Power and rabbi and benefit plan trust funds for Dominion.

Level 3—Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability. Instruments categorized in Level 3 for Dominion and Virginia Power consist of long-dated commodity derivatives, FTRs and other modeled commodity derivatives. Additional instruments categorized in Level 3 for Dominion include NGLs and natural gas peaking options and alternative investments, consisting of investments in partnerships, joint ventures and other alternative investments, held in benefit plan trust funds.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. In these cases, the lowest level input that is significant to a fair value measurement in its entirety determines the appli-

cable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Fair value measurements are categorized as Level 3 when a significant amount of price or other inputs that are considered to be unobservable are used in their valuations. Long-dated commodity derivatives are generally based on unobservable inputs due to the length of time to settlement and the absence of market activity and are therefore categorized as Level 3. For NGL derivatives, market illiquidity requires a valuation based on proxy markets that do not always correlate to the actual instrument, therefore they are categorized as Level 3. FTRs are categorized as Level 3 fair value measurements because the only relevant pricing available comes from ISO auctions, which is accurate for day-one valuation, but generally is not considered to be representative of the ultimate settlement values. Other modeled commodity derivatives have unobservable inputs in their valuation, mostly due to non-transparent and illiquid markets. Alternative investments are categorized as Level 3 due to the absence of quoted market prices, illiquidity and the long-term nature of these assets. These investments are generally valued using NAV based on the proportionate share of the fair value as determined by reference to the most recent audited fair value financial statements or fair value statements provided by the investment manager adjusted for any significant events occurring between the investment manager’s and the Companies’ measurement date.

For derivative contracts, Dominion and Virginia Power recognize transfers among Level 1, Level 2 and Level 3 based on fair values as of the first day of the month in which the transfer occurs. Transfers out of Level 3 represent assets and liabilities that were previously classified as Level 3 for which the inputs became observable for classification in either Level 1 or Level 2. Because the activity and liquidity of commodity markets vary substantially between regions and time periods, the availability of observable inputs for substantially the full term and value of the Companies’ over-the-counter derivative contracts is subject to change.

At December 31, 2010, Dominion’s and Virginia Power’s net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $50 million and a net asset of $14 million, respectively. A hypothetical 10% increase in commodity prices would increase Dominion’s net liability by $69 million and decrease Virginia Power’s net asset by $2 million. A hypothetical 10% decrease in commodity prices would decrease Dominion’s net liability by $66 million and increase Virginia Power’s net asset by $2 million.

Nonrecurring Fair Value Measurements

Partnership investments held by Virginia Power’s nuclear decommissioning trust funds and Dominion’s rabbi trust funds are accounted for as cost method investments. These investments are only subject to fair value measurement on a non-recurring basis when they have experienced an impairment, and are categorized as Level 3 fair value measurements. During 2009, substantially all of these partnership investments experienced impairments. During 2010, these partnership investments did not experience material impairments, therefore no such nonrecurring fair value measurements occurred.

In connection with partnership investments, Dominion and Virginia Power (as a limited partner) make capital commitments

that are called over time as the general partner makes investments. Investment strategies of the Companies’ partnership investments are primarily real estate and private equity-based. The typical term of these partnership investments is 10-15 years. The Companies have limited withdrawal or redemption rights during the term of the partnership. As a general rule, a limited partner’s interest can be sold in the secondary markets subject to the approval of the general partner. The secondary market tends to be illiquid especially during periods of market stress. Funds are returned to Dominion and Virginia Power as income, profits and capital are distributed over the term of the partnership.

Presented below are the fair values, unfunded commitments and estimated liquidation periods for partnership investments held by Virginia Power’s decommissioning trust funds and Dominion’s rabbi trust funds at December 31, 2009:


	Fair Value of Investments		Unfunded Commitments		Estimated Period of Liquidation
(millions)					(average years)
Decommissioning trust funds
Other investments	$	78	$	50		7
Real estate		19		30		5
Total		97		80		6
Rabbi trust funds
Other investments		10		3		5
Real estate		7		7		4
Total		17		10		4
Total decommissioning and rabbi trust funds	$	114	$	90		6

During 2009, Dominion evaluated an equity method investment for impairment and recorded a $30 million impairment in other income in its Consolidated Statement of Income. The resulting fair value of $4 million was estimated using a discounted cash flow model and is considered a Level 3 fair value measurement due to the use of significant unobservable inputs related to the timing and amount of future equity distributions based on the investee’s future financing structure, contractual and market-based revenues and operating costs.

During 2010, Dominion evaluated State Line, a coal-fired merchant power station with minimal environmental controls, for impairment due to the station’s relatively low level of profitability combined with the EPA’s issuance in June 2010 of a new stringent 1-hour primary NAAQS for SO₂ that will likely require significant environmental capital expenditures in the future. As a result of this evaluation, Dominion recorded an impairment charge of $163 million ($107 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down State Line’s long-lived assets to their estimated fair value of $59 million. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion relied on the income approach (discounted cash flows) to estimate the fair value of State Line’s long-lived assets. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices.

In December 2010, Dominion recorded an impairment charge of $31 million ($20 million after-tax) in other operations and maintenance expense in its Consolidated Statement of Income, to write down the long-lived assets of Salem Harbor to their estimated fair value of less than $1 million as a result of profitability issues. As management was not aware of any recent market transactions for comparable assets with sufficient transparency to develop a market approach to fair value, Dominion relied on the income approach to estimate the fair value of Salem Harbor’s long-lived assets. This was considered a Level 3 fair value measurement due to the use of significant unobservable inputs including estimates of future power and other commodity prices.

Recurring Fair Value Measurements

Fair value measurements are separately disclosed by level within the fair value hierarchy with a separate reconciliation of fair value measurements categorized as Level 3. Fair value disclosures for assets held in Dominion’s pension and other postretirement benefit plans are presented in Note 22.

DOMINION

The following table presents Dominion’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:


	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2010
Assets:
Derivatives:
Commodity	$	62	$	734	$	47	$	843
Interest Rate		—		54		—		54
Investments⁽¹⁾:
Equity securities:
U.S.:
Large Cap		1,709		—		—		1,709
Other		56		—		—		56
Non-U.S.:
Large Cap		12		—		—		12
Fixed Income:
Corporate debt instruments		—		327		—		327
U.S. Treasury securities and agency debentures		228		165		—		393
State and municipal		—		286		—		286
Other		—		19		—		19
Cash equivalents and other		25		97		—		122
Restricted cash equivalents		—		400		—		400
Total assets	$	2,092	$	2,082	$	47	$	4,221
Liabilities:
Derivatives:
Commodity	$	12	$	716	$	97	$	825
Interest Rate		—		5		—		5
Total liabilities	$	12	$	721	$	97	$	830
At December 31, 2009
Assets:
Derivatives:
Commodity	$	85	$	1,058	$	41	$	1,184
Interest Rate		—		176		—		176
Foreign Currency		—		2		—		2
Investments⁽¹⁾:
Equity securities:
U.S.:
Large Cap		1,520		—		—		1,520
Other		43		1		—		44
Non-U.S.:
Large Cap		12		—		—		12
Fixed Income:
Corporate debt instruments		—		253		—		253
U.S. Treasury securities and agency debentures		216		78		—		294
State and municipal		—		434		—		434
Other		—		4		—		4
Cash equivalents and other		—		54		—		54
Total assets	$	1,876	$	2,060	$	41	$	3,977
Liabilities:
Derivatives:
Commodity	$	17	$	736	$	107	$	860
Interest Rate		—		1		—		1
Total liabilities	$	17	$	737	$	107	$	861

(1)

Includes investments held in the nuclear decommissioning and rabbi trusts.

The following table presents the net change in Dominion’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:


	2010⁽¹⁾			2009⁽¹⁾			2008⁽¹⁾
(millions)
Balance at January 1,	$	(66	)	$	99		$	(61	)
Total realized and unrealized gains (losses):
Included in earnings		43			(148	)		(88	)
Included in other comprehensive income (loss)		(49	)		(188	)		274
Included in regulatory assets/liabilities		24			52			(59	)
Purchases, issuances and settlements		(38	)		126			85
Transfers out of Level 3		36			(7	)		(52	)
Balance at December 31,	$	(50	)	$	(66	)	$	99
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	(4	)	$	(3	)	$	(28	)

(1)

Represents derivative assets and liabilities presented on a net basis.

The following table presents Dominion’s gains and losses included in earnings in the Level 3 fair value category:


	Operating Revenue			Electric Fuel and Energy Purchases			Purchased Gas			Total
(millions)
Year Ended December 31, 2010
Total gains (losses) included in earnings	$	(4	)	$	51		$	(4	)	$	43
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		(4	)		—			—			(4	)

Year Ended December 31, 2009
Total gains (losses) included in earnings	$	29		$	(165	)	$	(12	)	$	(148	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		1			—			(4	)		(3	)

Year Ended December 31, 2008
Total gains (losses) included in earnings	$	(44	)	$	(28	)	$	(16	)	$	(88	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date		(6	)		(6	)		(16	)		(28	)

VIRGINIA POWER

The following table presents Virginia Power’s assets and liabilities that are measured at fair value on a recurring basis for each hierarchy level, including both current and noncurrent portions:


	Level 1		Level 2		Level 3		Total
(millions)
At December 31, 2010
Assets:
Derivatives:
Commodity	$	—	$	12	$	15	$	27
Investments⁽¹⁾:
Equity securities:
U.S.:
Large Cap		676		—		—		676
Other		25		—		—		25
Fixed Income:
Corporate debt instruments		—		215		—		215
U.S. Treasury securities and agency debentures		80		63		—		143
State and municipal		—		102		—		102
Other		—		15		—		15
Cash equivalents and other		10		61		—		71
Restricted cash equivalents		—		169		—		169
Total assets	$	791	$	637	$	15	$	1,443
Liabilities:
Derivatives:
Commodity	$	—	$	5	$	1	$	6
Total Liabilities	$	—	$	5	$	1	$	6
At December 31, 2009
Assets:
Derivatives:
Commodity	$	—	$	30	$	2	$	32
Interest Rate		—		86		—		86
Foreign Currency		—		2		—		2
Investments⁽¹⁾:
Equity securities:
U.S.:
Large Cap		615		—		—		615
Other		19		—		—		19
Fixed Income:
Corporate debt instruments		—		161		—		161
U.S. Treasury securities and agency debentures		90		8		—		98
State and municipal		—		189		—		189
Other		—		3		—		3
Cash equivalents and other		—		16		—		16
Total assets	$	724	$	495	$	2	$	1,221
Liabilities:
Derivatives:
Commodity	$	—	$	3	$	12	$	15
Total Liabilities	$	—	$	3	$	12	$	15

(1)

Includes investments held in the nuclear decommissioning trusts.

The following table presents the net change in Virginia Power’s assets and liabilities measured at fair value on a recurring basis and included in the Level 3 fair value category:


	2010⁽¹⁾			2009⁽¹⁾			2008⁽¹⁾
(millions)
Balance at January 1,	$	(10	)	$	(69	)	$	(4	)
Total realized and unrealized gains (losses):
Included in earnings		51			(165	)		(27	)
Included in regulatory assets/liabilities		24			53			(59	)
Purchases, issuances and settlements		(51	)		170			21
Transfers out of Level 3		—			1			—
Balance at December 31,	$	14		$	(10	)	$	(69	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to assets still held at the reporting date	$	—		$	—		$	(5	)

(1)

Represents derivative assets and liabilities presented on a net basis.

The gains and losses included in earnings in the Level 3 fair value category, including those attributable to the change in unrealized gains and losses relating to assets still held at the reporting date, were classified in electric fuel and other energy-related purchases expense in Virginia Power’s Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008.

Fair Value of Financial Instruments

Substantially all of Dominion’s and Virginia Power’s financial instruments are recorded at fair value, with the exception of the instruments described below that are reported at historical cost. Estimated fair values have been determined using available market information and valuation methodologies considered appropriate by management. The carrying amount of cash and cash equivalents, customer and other receivables, short-term debt and accounts payable are representative of fair value because of the short-term nature of these instruments. For Dominion’s and Virginia Power’s financial instruments that are not recorded at fair value, the carrying amounts and fair values are as follows:


At December 31,	2010				2009
	Carrying Amount		Estimated Fair Value⁽¹⁾		Carrying Amount		Estimated Fair Value⁽¹⁾
(millions)
Dominion
Long-term debt, including securities due within one year⁽²⁾	$	14,520	$	16,112	$	14,867	$	15,970
Junior subordinated notes payable to affiliates		268		261		268		255
Enhanced junior subordinated notes		1,467		1,560		1,483		1,487
Subsidiary preferred stock⁽³⁾		257		249		257		251

Virginia Power
Long-term debt, including securities due within one year⁽²⁾	$	6,717	$	7,489	$	6,458	$	6,977
Preferred stock⁽³⁾		257		249		257		251

(1)

Fair value is estimated using market prices, where available, and interest rates currently available for issuance of debt with similar terms and

remaining maturities. The carrying amount of debt issues with short-term maturities and variable rates refinanced at current market rates is a reasonable estimate of their fair value.

(2)

Includes amounts which represent the unamortized discount and premium. At December 31, 2010, and 2009, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of approximately $49 million and $23 million, respectively.

(3)

Includes issuance expenses of $2 million at December 31, 2010 and 2009.

NOTE 8. DERIVATIVES AND HEDGE ACCOUNTING ACTIVITIES

Dominion and Virginia Power are exposed to the impact of market fluctuations in the price of electricity, natural gas and other energy-related products they market and purchase, as well as currency exchange and interest rate risks of their business operations. The Companies use derivative instruments to manage exposure to these risks, and designate certain derivative instruments as fair value or cash flow hedges for accounting purposes. As discussed in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivatives are deferred as regulatory assets or regulatory liabilities until the related transactions impact earnings. See Note 7 for further information about fair value measurements and associated valuation methods for derivatives.

DOMINION

The following table presents the volume of Dominion’s derivative activity as of December 31, 2010. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting deals, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price⁽¹⁾		358		98
Basis⁽¹⁾		1,012		465
Electricity (MWh):
Fixed price		22,047,293		12,526,648
FTRs		49,301,662		1,817,176
Capacity (MW)		1,383,800		4,020,050
Liquids (gallons)⁽²⁾		148,764,000		361,536,000
Interest rate	$	—	$	1,000,000,000

(1)

Includes options.

(2)

Includes NGLs and oil.

Selected information about Dominion’s hedge accounting activities follows:


Year Ended December 31,	2010			2009			2008
(millions)
Portion of gains (losses) on hedging instruments determined to be ineffective and included in net income:
Fair value hedges⁽¹⁾	$	3		$	(4	)	$	(6	)
Cash flow hedges⁽²⁾		(1	)		—			(4	)
Net ineffectiveness	$	2		$	(4	)	$	(10	)
Gains (losses) attributable to changes in the time value of options and change in the differences between spot prices and forward prices and excluded from the assessment of effectiveness⁽³⁾:
Fair value hedges⁽⁴⁾	$	—		$	23		$	11
Total ineffectiveness and excluded amounts	$	2		$	19		$	1

(1)

For the year ended December 31, 2010, includes $(1) million recorded in purchased gas and $4 million recorded in operating revenue in Dominion’s Consolidated Statement of Income. For the year ended December 31, 2009, includes $(5) million recorded in purchased gas and $1 million recorded in operating revenue in Dominion’s Consolidated Statement of Income.

(2)

For the year ended December 31, 2010, includes $(3) million recorded in purchased gas and $2 million recorded in operating revenue in Dominion’s Consolidated Statement of Income.

(3)

Amounts excluded from the measurement of ineffectiveness related to cash flow hedges for the years ended December 31, 2010, 2009 and 2008 were not material.

(4)

For the year ended December 31, 2009, includes $22 million recorded in operating revenue and $1 million recorded in electric fuel and other energy-related purchases in Dominion’s Consolidated Statement of Income.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Dominion’s Consolidated Balance Sheet at December 31, 2010:


	AOCI After-Tax			Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax			Maximum Term
(millions)
Commodities:
Gas	$	(24	)	$	(13	)		48 months
Electricity		70			68			29 months
NGLs		(36	)		(15	)		48 months
Other		8			2			53 months
Interest rate		33			(1	)		336 months
Total	$	51		$	41

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated sales) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.

The sale of the majority of Dominion’s remaining E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges, as discussed in Note 4.

In addition, changes to Dominion’s financing needs during the first and second quarters of 2010 resulted in the discontinuance of hedge accounting for certain cash flow hedges since it was determined that the forecasted interest payments would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized a benefit recorded to interest and related charges reflecting the reclassification of gains from AOCI to earnings of $110 million ($67 million after-tax) for 2010. The reclassification of gains from AOCI to earnings was partially offset by subsequent changes in fair value for these contracts of $37 million ($23 million after-tax) for 2010.

Fair Value and Gains and Losses on Derivative Instruments

The following tables present the fair values of Dominion’s derivatives and where they are presented in its Consolidated Balance Sheets:

At December 31, 2010

Fair Value -
Derivatives
under
Hedge
Accounting

Fair Value -
Derivatives
not under
Hedge
Accounting

Total
Fair
Value

(millions)

ASSETS

Current Assets

Commodity

291

425

716

Interest rate

—

Total current derivative assets

314

425

739

Noncurrent Assets

Commodity

127

Interest rate

—

Total noncurrent derivative assets⁽¹⁾

158

Total derivative assets

389

508

897

LIABILITIES

Current Liabilities

Commodity

178

455

633

Total current derivative liabilities

178

455

633

Noncurrent Liabilities

Commodity

106

192

Interest rate

—

Total noncurrent derivative liabilities⁽²⁾

106

197

Total derivative liabilities

269

561

830

(1)

Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

(2)

Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.


At December 31, 2009	Fair Value - Derivatives under Hedge Accounting		Fair Value - Derivatives not under Hedge Accounting		Total Fair Value
(millions)
ASSETS
Current Assets
Commodity	$	445	$	507	$	952
Interest rate		174		—		174
Foreign Currency		2		—		2
Total current derivative assets		621		507		1,128
Noncurrent Assets
Commodity		132		100		232
Interest rate		2		—		2
Total noncurrent derivative assets⁽¹⁾		134		100		234
Total derivative assets	$	755	$	607	$	1,362
LIABILITIES
Current Liabilities
Commodity	$	147	$	532	$	679
Total current derivative liabilities		147		532		679
Noncurrent Liabilities
Commodity		61		120		181
Interest rate		1		—		1
Total noncurrent derivative liabilities⁽²⁾		62		120		182
Total derivative liabilities	$	209	$	652	$	861

(1)

Noncurrent derivative assets are presented in other deferred charges and other assets in Dominion’s Consolidated Balance Sheet.

(2)

Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Dominion’s Consolidated Balance Sheet.

The following tables present the gains and losses on Dominion’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:


Year ended December 31, 2010 Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue				$	557
Purchased gas					(155	)
Electric fuel and other energy-related purchases					(8	)
Purchased electric capacity					3
Total commodity	$	139			397		$	(17	)
Interest rate⁽³⁾		(3	)		109			(27	)
Foreign currency⁽⁴⁾		—			1			(2	)
Total	$	136		$	507		$	(46	)



Year ended December 31, 2009 Derivatives in cash flow hedging relationships	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾		Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Derivative Type and Location of Gains (Losses)
Commodity:
Operating revenue			$	1,072
Purchased gas				(179	)
Electric fuel and other energy-related purchases				(10	)
Purchased electric capacity				4
Total commodity	$	358	$	887		$	6
Interest rate⁽³⁾		159		(4	)		87
Foreign currency⁽⁴⁾		—		2			(3	)
Total	$	517	$	885		$	90

(1)

Amounts deferred into AOCI have no associated effect in Dominion’s Consolidated Statements of Income.

(2)

Represents net derivative activity deferred into and amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.

(3)

Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.

(4)

Amounts recorded in Dominion’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.


Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
Year ended December 31,	2010		2009
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue	$	67	$	105
Purchased gas		(41)		(66	)
Electric fuel and other energy-related purchases		51		(163	)
Interest rate⁽²⁾		(37)		—
Total	$	40	$	(124	)

(1)

Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Dominion’s Consolidated Statements of Income.

(2)

Amounts recorded in Dominion’s Consolidated Statements of Income are classified in interest and related charges.

VIRGINIA POWER

The following table presents the volume of Virginia Power’s derivative activity at December 31, 2010. These volumes are based on open derivative positions and represent the combined absolute value of their long and short positions, except in the case of offsetting deals, for which they represent the absolute value of the net volume of their long and short positions.


	Current		Noncurrent
Natural Gas (bcf):
Fixed price		10		—
Basis		5		—
Electricity (MWh):
Fixed price		651,200		—
FTRs		48,141,239		1,817,176
Capacity (MW)		288,200		258,500

For the years ended December 31, 2010, 2009 and 2008, gains or losses on hedging instruments determined to be ineffective and amounts excluded from the assessment of effectiveness were not material. Amounts excluded from the assessment of effectiveness include gains or losses attributable to the time value of options and changes in the differences between spot prices and forward prices.

The following table presents selected information related to gains (losses) on cash flow hedges included in AOCI in Virginia Power’s Consolidated Balance Sheet at December 31, 2010:


	AOCI After-Tax		Amounts Expected to be Reclassified to Earnings during the next 12 Months After-Tax		Maximum Term
(millions)
Interest rate	$	3	$	—		336 months
Other		1		1		41 months
Total	$	4	$	1

The amounts that will be reclassified from AOCI to earnings will generally be offset by the recognition of the hedged transactions (e.g., anticipated interest payments) in earnings, thereby achieving the realization of prices contemplated by the underlying risk management strategies and will vary from the expected amounts presented above as a result of changes in market prices and interest rates.

The following tables present the fair values of Virginia Power’s derivatives and where they are presented in its Consolidated Balance Sheets:

The following tables present the gains and losses on Virginia Power’s derivatives, as well as where the associated activity is presented in its Consolidated Balance Sheets and Statements of Income:

NOTE 9. EARNINGS PER SHARE

The following table presents the calculation of Dominion’s basic and diluted EPS:


	2010		2009		2008
(millions, except EPS)
Net income attributable to Dominion	$	2,808	$	1,287	$	1,834
Average shares of common stock outstanding—Basic		588.9		593.3		577.8
Net effect of potentially dilutive securities⁽¹⁾		1.2		0.4		3.0
Average shares of common stock outstanding—Diluted		590.1		593.7		580.8
Earnings Per Common Share—Basic	$	4.77	$	2.17	$	3.17
Earnings Per Common Share—Diluted	$	4.76	$	2.17	$	3.16

(1)

Potentially dilutive securities consist of options, goal-based stock and contingently convertible senior notes.

Potentially dilutive securities with the right to acquire approximately 1.2 million common shares for the year ended December 31, 2009 were not included in the calculation of diluted EPS because the exercise or purchase prices of those instruments were greater than the average market price of Dominion’s common shares. There were no potentially dilutive securities excluded from the calculation of diluted EPS for the years ended December 31, 2010 and 2008.

Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $93 million and $96 million at December 31, 2010 and 2009, respectively. Net unrealized gains on trading securities totaled $5 million and $11 million in 2010 and 2009, respectively, and net unrealized losses on trading securities totaled $26 million in 2008. Cost-method investments held in Dominion’s rabbi trusts totaled $18 million and $17 million at December 31, 2010 and 2009, respectively.

Dominion holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Dominion’s decommissioning trust funds are summarized below.

ceeds reflected in Dominion’s Consolidated Statement of Cash Flows from the sale of temporary investments consisting of time deposits and Treasury Bills, purchased following the sale of substantially all of Dominion’s Appalachian E&P operations.

(2)

The increase in proceeds primarily reflects changes in asset allocation and liquidation of positions in connection with changes in fund managers.

(3)

Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.

Dominion recorded other-than-temporary impairment losses on investments held in nuclear decommissioning trust funds as follows:


Year Ended December 31,	2010			2009			2008
(millions)
Total other-than-temporary impairment losses⁽¹⁾	$	59		$	175		$	344
Losses recorded to decommissioning trust regulatory liability		(21	)		(80	)		(105	)
Losses recognized in other comprehensive income (before taxes)		(3	)		(3	)		—
Net impairment losses recognized in earnings	$	35		$	92		$	239

(1)

Amounts include other-than-temporary impairment losses for debt securities of $10 million, $13 million and $28 million at December 31, 2010, 2009 and 2008, respectively.

Equity Method Investments

Investments that Dominion accounts for under the equity method of accounting are as follows:


Company	Ownership%			Investment Balance				Description
As of December 31,				2010		2009
(millions)
Fowler I Holdings LLC⁽¹⁾		50	%	$	180	$	193		Wind-powered merchant generation facility
NedPower Mount Storm LLC		50	%		149		157		Wind-powered merchant generation facility
Iroquois Gas Transmission System, LP		24.72	%		106		102		Gas transmission system
Elwood Energy LLC		50	%		98		90		Natural gas-fired merchant generation peaking facility
Other		various			38		53
Total				$	571	$	595

(1)

In September 2009, Dominion received a $123 million distribution from Fowler Ridge based on proceeds received in connection with non-recourse permanent financing for the first phase of the project.

Dominion’s equity earnings on these investments totaled $42 million in both 2010 and 2009 and $52 million in 2008. Excluding the 2009 distribution from Fowler Ridge, Dominion received distributions from these investments of $60 million, $63 million and $12 million in 2010, 2009, and 2008, respectively. As of December 31, 2010 and 2009, the carrying amount of Dominion’s investments exceeded Dominion’s share of underlying equity in net assets by approximately $7 million and $19 million, respectively. Excluding the impairment losses discussed below, the differences relate to Dominion’s investments in wind projects and primarily reflect its capitalized interest during construction and the excess of its cash contributions over the book value of development assets contributed by Dominion’s partners for these projects. The differences are generally being amortized over the

useful lives of the underlying assets.

During 2009, Dominion recognized total impairment losses of $30 million in connection with a decline in estimated fair value of one of its equity method investments as discussed in Note 7. During 2008, Dominion recognized a $7 million gain on the sale of one of its equity method investments.

VIRGINIA POWER

Virginia Power holds marketable equity and debt securities (classified as available-for-sale), cash equivalents and cost method investments in nuclear decommissioning trust funds to fund future decommissioning costs for its nuclear plants. Virginia Power’s decommissioning trust funds are summarized below.


	Amortized Cost		Total Unrealized Gains ⁽¹⁾		Total Unrealized Losses ⁽¹⁾			Fair Value⁽²⁾
(millions)
2010
Marketable equity securities:
U.S.:
Large Cap	$	469	$	207	$	—		$	676
Other		20		5		—			25
Marketable debt securities:
Corporate debt instruments		205		10		—			215
U.S. Treasury securities and agency debentures		141		2		—			143
State and municipal		103		1		(2	)		102
Other		15		—		—			15
Cost method investments		108		—		—			108
Cash equivalents and other		35		—		—			35
Total	$	1,096	$	225	$	(2	)⁽³⁾	$	1,319
2009
Marketable equity securities:
U.S.:
Large Cap	$	489	$	126	$	—		$	615
Other		10		9		—			19
Marketable debt securities:
Corporate debt instruments		153		9		(1	)		161
U.S. Treasury securities and agency debentures		95		3		—			98
State and municipal		181		9		(1	)		189
Other		3		—		—			3
Cost method investments		97		—		—			97
Cash equivalents and other		22		—		—			22
Total	$	1,050	$	156	$	(2	)⁽³⁾	$	1,204

(1)

Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.

(2)

Includes pending purchases of securities of $35 million at December 31, 2010. Includes pending sales of securities of $6 million at December 31, 2009.

(3)

The fair value of securities in an unrealized loss position was $159 million and $88 million at December 31, 2010 and 2009, respectively.

The fair value of Virginia Power’s debt securities at December 31, 2010, by contractual maturity is as follows:


	Amount
(millions)
Due in one year or less	$	—
Due after one year through five years		151
Due after five years through ten years		167
Due after ten years		157
Total	$	475

Presented below is selected information regarding Virginia Power’s marketable equity and debt securities.


Year Ended December 31,	2010			2009			2008
(millions)
Proceeds from sales	$	1,192	⁽¹⁾	$	715	⁽²⁾	$	410
Realized gains⁽³⁾		52			104			45
Realized losses⁽³⁾		23			99			143

(1)

The increase in proceeds primarily reflects the replacement of commingled funds with actively managed portfolios.

(2)

The increase in proceeds primarily reflects changes in asset allocation and liquidation of positions in connection with changes in fund managers.

(3)

Includes realized gains and losses recorded to the decommissioning trust regulatory liability as discussed in Note 2.

Virginia Power recorded other-than-temporary impairment losses on investments as follows:


Year Ended December 31,	2010			2009			2008
(millions)
Total other-than-temporary impairment losses⁽¹⁾	$	25		$	94		$	123
Losses recorded to decommissioning trust regulatory liability		(21	)		(80	)		(105	)
Losses recorded in other comprehensive income (before taxes)		(1	)		—			—
Net impairment losses recognized in earnings	$	3		$	14		$	18

(1)

Amounts include other-than-temporary impairment losses for debt securities of $6 million, $7 million and $5 million at December 31, 2010, 2009 and 2008, respectively.

Other Investments

Dominion and Virginia Power hold restricted cash and cash equivalent balances that primarily consist of money market fund investments held in trust for the purpose of funding certain qualifying construction projects. At December 31, 2010 and 2009, Dominion had $415 million and $18 million, respectively, and Virginia Power had $169 million and $4 million, respectively, of restricted cash and cash equivalents. These balances are presented in Other Current Assets and Investments in the Consolidated Balance Sheets.

NOTE 11. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment and their respective balances for the Companies are as follows:


At December 31,	2010		2009
(millions)
Dominion
Utility:
Generation	$	11,381	$	11,105
Transmission		5,793		5,003
Distribution		9,883		9,415
Storage		1,892		1,837
Nuclear fuel		1,058		994
Gas gathering and processing		535		492
General and other		730		737
Other—including plant under construction		3,933		3,110
Total utility		35,205		32,693
Nonutility:
Proved E&P properties being amortized		103		1,904
Unproved E&P properties not being amortized		—		8
Merchant generation—nuclear		1,217		1,107
Merchant generation—other		1,451		1,657
Nuclear fuel		762		720
Other—including plant under construction		1,117		947
Total nonutility		4,650		6,343
Total property, plant and equipment	$	39,855	$	39,036

Virginia Power
Utility:
Generation	$	11,381	$	11,105
Transmission		3,080		2,511
Distribution		7,879		7,568
Nuclear fuel		1,058		994
General and other		591		591
Other—including plant under construction		3,610		2,866
Total utility		27,599		25,635
Nonutility—other		8		8
Total property, plant and equipment	$	27,607	$	25,643

Costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2010 and 2009 were not material. There were no significant E&P properties under development, as defined by the SEC, excluded from amortization at December 31, 2010 and 2009.

Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2010 is as follows:

The co-owners are obligated to pay their share of all future construction expenditures and operating costs of the jointly-owned facilities in the same proportion as their respective ownership interest. Dominion and Virginia Power report their share of operating costs in the appropriate operating expense (electric fuel and other energy-related purchases, other operations and maintenance, depreciation, depletion and amortization and other taxes, etc.) in the Consolidated Statements of Income.

In December 2009, Dominion made the decision to retain Hope and include it with East Ohio in Dominion’s gas distribution business within the Dominion Energy segment. Goodwill was allocated from the Corporate and Other segment to the Dominion Energy segment based on the relative fair values of Hope and Peoples, which remained held-for-sale within the Dominion Corporate and Other segment. Dominion did not perform an interim impairment test in 2009 as no events occurred that would more-likely-than-not reduce the reporting units’ fair values below their carrying values.

The changes in Dominion’s carrying amount and segment allocation of goodwill are presented below:

Other Intangible Assets

Dominion’s and Virginia Power’s other intangible assets are subject to amortization over their estimated useful lives. Dominion’s amortization expense for intangible assets was $107 million, $155 million and $95 million for 2010, 2009 and 2008, respectively. In 2010, Dominion acquired $61 million of intangible assets, primarily representing software and emissions allowances, with estimated weighted-average amortization periods of approximately 5 years and 1 year, respectively. Amortization expense for Virginia Power’s intangible assets was $26 million, $26 million, and $28 million for 2010, 2009 and 2008, respectively. In 2010, Virginia Power acquired $20 million of intangible assets, primarily representing software, with an estimated weighted-average amortization period of 5 years. The components of intangible assets are as follows:


At December 31,	2010				2009
	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
(millions)
Dominion
Software and software licenses	$	651	$	295	$	657	$	325
Emissions allowances		134		50		229		74
Other		241		39		237		31
Total	$	1,026	$	384	$	1,123	$	430

Virginia Power
Software and software licenses	$	251	$	124	$	265	$	149
Emissions allowances		48		3		68		5
Other		56		16		53		15
Total	$	355	$	143	$	386	$	169

Annual amortization expense for these intangible assets is estimated to be as follows:


	2011		2012		2013		2014		2015
(millions)
Dominion	$	81	$	57	$	46	$	34	$	27

Virginia Power	$	21	$	20	$	14	$	11	$	6

NOTE 13. REGULATORY ASSETS AND LIABILITIES

Regulatory assets and liabilities include the following:


At December 31,	2010		2009
(millions)
Dominion
Regulatory assets:
Deferred cost of fuel used in electric generation⁽¹⁾	$	174	$	41
Deferred transmission costs⁽²⁾		76		—
PIPP⁽³⁾		44		—
Unrecovered gas costs⁽⁴⁾		39		52
Virginia sales taxes⁽⁵⁾		35		34
Other		39		43
Regulatory assets-current		407		170
Unrecognized pension and other postretirement benefit costs⁽⁶⁾		987		968
Deferred cost of fuel used in electric generation⁽¹⁾		153		—
PIPP⁽³⁾		—		143
Income taxes recoverable through future rates⁽⁷⁾		90		75
Deferred transmission costs⁽²⁾		49		61
Other postretirement benefit costs⁽⁸⁾		29		36
Other		138		107
Regulatory assets-non-current		1,446		1,390
Total regulatory assets	$	1,853	$	1,560
Regulatory liabilities:
Provision for rate proceedings⁽⁹⁾	$	79	$	473
Other		56		63
Regulatory liabilities-current		135		536
Decommissioning trust⁽¹⁰⁾		391		324
Provision for future cost of removal and AROs⁽¹¹⁾		830		766
Derivatives⁽¹²⁾		68		105
Other		103		20
Regulatory liabilities-non-current		1,392		1,215
Total regulatory liabilities	$	1,527	$	1,751

Virginia Power
Regulatory assets:
Deferred cost of fuel used in electric generation⁽¹⁾	$	174	$	41
Deferred transmission costs⁽²⁾		76		—
Virginia sales taxes⁽⁵⁾		35		34
Other		33		41
Regulatory assets-current		318		116
Deferred cost of fuel used in electric generation⁽¹⁾		153		—
Income taxes recoverable through future rates⁽⁷⁾		76		67
Deferred transmission costs⁽²⁾		49		61
Other		92		72
Regulatory assets-non-current		370		200
Total regulatory assets	$	688	$	316
Regulatory liabilities:
Provision for rate proceedings⁽⁹⁾	$	79	$	473
Other		30		18
Regulatory liabilities-current		109		491
Provision for future cost of removal⁽¹¹⁾		622		562
Decommissioning trust⁽¹⁰⁾		391		324
Derivatives⁽¹²⁾		68		105
Other		93		4
Regulatory liabilities-non-current		1,174		995
Total regulatory liabilities	$	1,283	$	1,486

(1)

Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations, net of $63 million of damages awarded to Virginia Power for spent nuclear fuel costs through June 30, 2006 returned to customers but not yet received. See Notes 14 and 23 for more information.

(2)

Reflects deferrals under the electric transmission FERC formula rate and the deferral of transmission-related costs associated with Rider T. See Note 14 for more information.

(3)

Under PIPP, eligible customers can receive energy assistance based on their ability to pay. The difference between the customer’s total bill and the PIPP plan amount is deferred and collected annually under the PIPP rider according to East Ohio tariff provisions. See Note 14 for more information regarding PIPP.

(4)

Reflects unrecovered gas costs at Dominion’s regulated gas operations, which are recovered through quarterly or annual filings with the applicable regulatory authority.

(5)

Amounts to be recovered through an annual surcharge to reimburse Virginia Power for incremental sales taxes being incurred due to the repeal of the public service company sales tax exemption in Virginia.

(6)

Represents unrecognized pension and other postretirement benefit costs expected to be recovered through future rates by certain of Dominion’s rate-regulated subsidiaries.

(7)

Amounts to be recovered through future rates to pay income taxes that become payable when rate revenue is provided to recover AFUDC-equity and depreciation of property, plant and equipment for which deferred income taxes were not recognized for ratemaking purposes, including amounts attributable to tax rate changes.

(8)

Costs recognized in excess of amounts included in regulated rates charged by Dominion’s regulated gas operations before rates were updated to reflect a change in accounting method for other postretirement benefit costs and the cost related to the accrued benefit obligation recognized as part of accounting for Dominion’s acquisition of CNG.

(9)

Reflects a reserve associated with the settlement of Virginia Power’s 2009 base rate case proceedings. See Note 14 for more information.

(10)

Primarily reflects a regulatory liability representing amounts collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of Virginia Power’s utility nuclear generation stations, in excess of the related ARO.

(11)

Rates charged to customers by the Companies’ regulated businesses include a provision for the cost of future activities to remove assets that are expected to be incurred at the time of retirement.

(12)

As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based rate regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities as they are expected to be recovered from or refunded to customers.

At December 31, 2010, approximately $81 million of Dominion’s and $22 million of Virginia Power’s regulatory assets represented past expenditures on which they do not currently earn a return. Dominion’s expenditures primarily include unrecovered gas costs. The above expenditures are expected to be recovered within the next two years.

NOTE 14. REGULATORY MATTERS

The following is a discussion of Dominion’s and Virginia Power’s pending regulatory matters.

Electric Regulation in Virginia

The Regulation Act also authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, FERC-approved transmission costs, environmental compliance, conservation and energy efficiency programs and renewable energy programs. The Regulation Act provides for enhanced returns on capital expenditures on specific new generation projects, including but not limited to nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects. The Regulation Act also continues statutory provisions directing Virginia Power to file annual fuel cost recovery cases with the Virginia Commission.

The Virginia Settlement Approval Order included the following provisions:

Credits from 2008 Revenues

Credits to customers of $400 million from Virginia Power’s 2008 revenues to be applied against base rates and rider charges.

Base Rates

No change in Virginia Power’s base rates in existence prior to September 1, 2009 until December 1, 2013 (unless emergency rate relief is warranted by statute);

Refund increased revenues collected under the interim base rates since September 1, 2009; and

An ROE of 11.9% (inclusive of a performance incentive of 60 basis points) for use in the Virginia Commission’s assessment in the upcoming biennial rate review of Virginia Power’s earnings.

FTR Credits

Credits to customers of $129 million, inclusive of any carrying charge, relating to revenues from FTRs for the period July 1, 2007 through June 30, 2009.

Generation Riders R and S

An ROE of 12.3% (inclusive of a 100 basis point statutory enhancement) for the 2010 rate year.

Transmission Rider T

DSM Riders C1 and C2

An ROE of 11.3% for the 2010 rate year.

Virginia Power previously 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 Virginia Power’s retail customers by ten percent of what was consumed in 2006. In March 2010, the Virginia Commission approved the recovery of approximately $28 million for five of the DSM programs through initiation of Riders C1 and C2, effective May 1, 2010. With respect to the other six DSM programs for which approval was sought, the Virginia Commission made a finding that they were not in the public interest at that time, but allowed Virginia Power the opportunity for further evaluation of similar programs. In July 2010, Virginia Power submitted its annual update filing for Riders C1 and C2 with respect to the five approved DSM programs. The proposed revenue requirements for Riders C1 and C2 were approximately $6 million and $18 million, respectively, which together represent a decrease of approximately $5 million compared to the revenue requirements included in Riders C1 and C2 customer rates currently in effect. In February 2011, an evidentiary hearing was held by the Virginia Commission on Virginia Power’s update of Riders C1 and C2. The Virginia Commission is required to issue its order by March 30, 2011. Virginia Power plans to seek Virginia Commission approval for several DSM programs in 2011.

In connection with the Bear Garden and Virginia City Hybrid Energy Center projects, in June 2010, Virginia Power filed annual updates for Riders R and S, respectively, with the Virginia Commission. Initially, Virginia Power proposed an approximately $86 million revenue requirement for Rider R for the April 1, 2011 to March 31, 2012 rate year. Due to the application of accelerated tax depreciation provisions in the Small Business Jobs Act of 2010, passed in September 2010, Virginia Power revised the requested revenue requirement for Rider R in November 2010 from $86 million to $78 million. The adjusted $78 million revenue requirement represents an increase of approximately $14 million over the revenue requirement associated with the Rider R customer rates currently in effect. The proposed Rider S revenue requirement, effective April 1, 2011, for the rate year ending March 31, 2012 is approximately $200 million, which represents an increase of $46 million over the revenue requirement associated with the Rider S customer rates currently in effect. The ROE included in both rider filings is 12.3%, consistent with the terms of the Virginia Settlement Approval Order. In July 2010, the Virginia Commission issued

orders with respect to Riders R and S, which adopted a placeholder ROE of 11.3% (not including the 100 basis point statutory enhancement) for use until the ROE is determined in the context of Virginia Power’s upcoming biennial review. Evidentiary hearings were held by the Virginia Commission on Riders R and S in December and November 2010, respectively. The Virginia Commission is required to issue its orders on these proceedings by March 30, 2011.

North Carolina Regulation

current rates. In addition, the North Carolina Settlement Approval Order permits the recovery through fuel rates of 85% of the net energy costs of power purchases from both PJM and other wholesale suppliers and from the non-utility generators subject to economic dispatch that do not provide actual cost data. The North Carolina Settlement Approval Order authorizes an ROE of 10.7% and a capital structure composed of 49% long-term debt and 51% common equity. The new base and fuel rates became effective on January 1, 2011.

Ohio and West Virginia Regulation

In the fourth quarter of 2008, the Ohio Commission approved an approximately $41 million annual revenue increase for East Ohio and a return on rate base that incorporates an ROE of 10.38%. These changes were reflected in revised base rates commencing December 22, 2008.

In October 2008, the Ohio Commission approved cost recovery for an initial five-year period of East Ohio’s 25-year PIR program to replace approximately 20% of its 21,000-mile pipeline system. In August 2010, East Ohio filed its second annual application to adjust the cost recovery charge associated with its PIR program for actual costs and a return on investments made through June 30, 2010. The application reflected a revenue requirement of approximately $28 million. In November 2010, the Ohio Commission approved a settlement agreement filed by East Ohio and the Staff of the Ohio Commission reflecting a revenue requirement of approximately $27 million. Other interested parties to the case neither supported nor objected to the settlement agreement.

East Ohio files an annual UEX Rider with the Ohio Commission, pursuant to which it seeks recovery of the bad debt expense of most customers not participating in PIPP Plus. The UEX

Rider is adjusted annually to achieve dollar-for-dollar recovery of East Ohio’s actual write-offs of uncollectable amounts. In 2010, East Ohio deferred approximately $55 million of bad debt expense for recovery through the UEX Rider.

Federal Regulation

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 the issue of existing facilities back to FERC for further proceedings. Although Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand, the impact of any PJM rate design changes on the Companies’ results of operations is not expected to be material.

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. Although Virginia Power cannot predict the outcome of the rehearing, it is not expected to have a material effect on results of operations.

In March 2010, ODEC and NCEMC filed a complaint with FERC against Virginia Power claiming that approximately $223 million in transmission costs related to specific projects were unjust, unreasonable and unduly discriminatory or preferential and should be excluded from Virginia Power’s transmission formula rate. ODEC and NCEMC requested that FERC establish procedures to determine the amount of costs for each applicable project that should be excluded from Virginia Power’s rates. In October 2010, FERC issued an order dismissing the complaint in part and established hearings and settlement procedures on the remaining part of the complaint. While Virginia Power cannot predict the outcome of this proceeding, it is not expected to have a material effect on results of operations.

In addition, NERC has requested the industry to increase the number of assets subject to NERC reliability standards that are designated as critical assets, including cyber security assets. While Dominion and Virginia Power expect to incur additional compliance costs in connection with the above NERC requirements and initiatives, such expenses are not expected to significantly affect results of operations.

Dominion Transmission Rates

NOTE 15. ASSET RETIREMENT OBLIGATIONS

AROs represent obligations that result from laws, statutes, contracts and regulations related to the eventual retirement of certain of Dominion’s and Virginia Power’s long-lived assets. Dominion’s and Virginia Power’s AROs are primarily associated with the decommissioning of their nuclear generation facilities. In addition, Dominion’s AROs include plugging and abandonment of gas and oil wells, interim retirements of natural gas gathering, transmission, distribution and storage pipeline components, and the future abatement of asbestos expected to be disturbed in the Companies’ generation facilities.

The Companies have also identified, but not recognized, AROs related to retirement of Dominion’s LNG facility, Dominion’s gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, rights of way, franchises and lease agreements, Virginia Power’s hydroelectric generation facilities and the abatement of certain asbestos not expected to be disturbed in the Companies’ generation facilities. The Companies currently do not have sufficient information to estimate a reasonable range of expected retirement dates for any of these assets since the economic lives of these assets can be extended indefinitely through regular repair and maintenance and they currently have no plans to retire or dispose of any of these assets. As a result, a settlement date is not determinable for these assets and AROs for these assets will not be reflected in the Consolidated Financial Statements until sufficient information becomes available to determine a reasonable estimate of the fair value of the activities to be performed. The Companies continue to monitor operational and strategic developments to

identify if sufficient information exists to reasonably estimate a retirement date for these assets. The changes to AROs during 2009 and 2010 were as follows:


	Amount
(millions)
Dominion
AROs at December 31, 2008⁽¹⁾	$	1,822
Obligations incurred during the period		14
Obligations settled during the period		(13	)
Revisions in estimated cash flows⁽²⁾		(304	)
Accretion		88
Other		7
AROs at December 31, 2009⁽¹⁾	$	1,614
Obligations incurred during the period		1
Obligations settled during the period		(9	)
Revisions in estimated cash flows		5
Accretion		85
Obligations relieved due to sale of Appalachian E&P operations		(105	)
AROs at December 31, 2010⁽¹⁾	$	1,591

Virginia Power
AROs at December 31, 2008⁽³⁾	$	717
Revisions in estimated cash flows⁽²⁾		(115	)
Accretion		35
AROs at December 31, 2009⁽³⁾	$	637
Accretion		35
AROs at December 31, 2010⁽³⁾	$	672

(1)

Includes $20 million, $9 million and $14 million reported in other current liabilities at December 31, 2008, 2009, and 2010, respectively.

(2)

Primarily reflects updated decommissioning cost studies and applicable escalation rates received for the Companies’ nuclear facilities during the second quarter of 2009. For Dominion, also includes a $103 million ($62 million after-tax) reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service.

(3)

Includes $2 million, $1 million and $3 million reported in other current liabilities at December 31, 2008, 2009 and 2010, respectively.

Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2010 and 2009, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $2.9 billion and $2.6 billion, respectively. At December 31, 2010 and 2009, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.3 billion and $1.2 billion, respectively.

NOTE 16. VARIABLE INTEREST ENTITIES

The primary beneficiary of a VIE is required to consolidate the VIE and to disclose certain information about its significant variable interests in the VIE. The primary beneficiary of a VIE is the entity that has both 1) the power to direct the activities that most significantly impact the entity’s economic performance and 2) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE.

Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate generation capacity of approximately 974 MW. These contracts contain certain variable pricing mechanisms in the form of partial fuel reimbursement that Virginia Power considers to be variable interests. After an evaluation of the information provided by these entities, Virginia Power was unable to determine whether they were VIEs. However, the information they provided, as well as Virginia Power’s knowledge of generation facilities in Virginia, enabled Virginia Power to conclude that, if they were VIEs, it would not be the primary beneficiary. This conclusion reflects Virginia Power’s determination that its variable interests do not convey the power to direct the most significant activities that impact the economic performance of the entities during the remaining terms of Virginia Power’s contracts and for the years the entities are expected to operate after its contractual relationships expire. The contracts expire at various dates ranging from 2015 to 2021. Virginia Power is not subject to any risk of loss from these potential VIEs other than its remaining purchase commitments which totaled $1.5 billion as of December 31, 2010. Virginia Power paid $213 million, $210 million, and $205 million for electric capacity and $164 million, $117 million, and $196 million for electric energy to these entities for the years ended December 31, 2010, 2009 and 2008, respectively.

As discussed in Note 25, DCI held an investment in the subordinated notes of a third-party CDO entity. Dominion previously concluded that the CDO entity was a VIE and that DCI was the primary beneficiary of the CDO entity, which Dominion consolidated at December 31, 2007. In March 2008, Dominion entered into an agreement to sell its remaining interest in the subordinated notes effectively eliminating the variability of its interest, and therefore deconsolidated the CDO entity as of March 31, 2008.

Virginia Power purchased shared services from DRS, an affiliated VIE, of approximately $465 million, $416 million, and $397 million for the years ended December 31, 2010, 2009 and 2008, respectively. Virginia Power determined that it is not the most closely associated entity with DRS and therefore not the primary beneficiary. DRS provides accounting, legal, finance and certain administrative and technical services to all Dominion subsidiaries, including Virginia Power. Virginia Power has no obligation to absorb more than its allocated share of DRS costs.

NOTE 17. SHORT-TERM DEBT AND CREDIT AGREEMENTS

DOMINION

Commercial paper, bank loans, and letters of credit outstanding, as well as capacity available under credit facilities were as follows:


At December 31,	Facility Limit		Out- standing Commercial Paper			Out- standing Bank Borrowings			Out- standing Letters of Credit		Facility Capacity Available
(millions)
2010
Three-year joint revolving credit facility⁽¹⁾	$	3,000	$	1,386		$	—		$	101	$	1,513
Three-year joint revolving credit facility⁽²⁾		500		—			—			35		465
Total	$	3,500	$	1,386	⁽⁶⁾	$	—		$	136	$	1,978
2009
Five-year joint revolving credit facility⁽³⁾	$	2,872	$	442		$	—		$	153	$	2,277
Five-year Dominion credit facility⁽⁴⁾		1,700		353			500			19		828
Five-year Dominion bilateral facility⁽⁵⁾		200		—			—			32		168
Total	$	4,772	$	795	⁽⁶⁾	$	500	⁽⁷⁾	$	204	$	3,273

(1)

(2)

(3)

This credit facility was entered into in February 2006 and terminated in September 2010. This credit facility was used to support bank borrowings, commercial paper and letter of credit issuances.

(4)

This credit facility was entered into in August 2005 and terminated in August 2010. This facility was used to support bank borrowings, the issuance of letters of credit and commercial paper.

(5)

This facility was entered into in December 2005 and terminated in December 2010. This credit facility was used to support commercial paper and letter of credit issuances.

(6)

The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.41% and 0.30% at December 31, 2010 and 2009, respectively.

(7)

The weighted-average interest rate of the outstanding bank borrowings supported by Dominion’s credit facilities was 0.33% at December 31, 2009.

VIRGINIA POWER

Virginia Power’s share of commercial paper, bank loans, and letters of credit outstanding, as well as its capacity available under its joint credit facilities with Dominion were as follows:

December 31,

Facility
Sub-limit

Outstanding
Commercial
Paper

Outstanding
Letters of
Credit

Facility
Capacity
Available

(millions)

2010

Three-year joint revolving credit facility⁽¹⁾

1,000

600

309

Three-year joint revolving credit facility⁽²⁾

250

—

250

Total

1,250

600

⁽³⁾

559

(1)

(2)

(3)

The weighted-average interest rate of the outstanding commercial paper supported by these credit facilities was 0.41% at December 31, 2010.

At December 31, 2009, Virginia Power had $442 million of commercial paper and $104 million of letters of credit outstanding under a five-year, $2.8 billion joint credit facility with Dominion and the weighted-average interest rate of its outstanding commercial paper was 0.28%. This credit facility was entered into in February 2006 and terminated in September 2010. This credit facility was used to support bank borrowings, commercial paper and letter of credit issuances.

Based on stated maturity dates rather than early redemption dates that could be elected by instrument holders, the scheduled principal payments of long-term debt at December 31, 2010, were as follows:

Dominion’s and Virginia Power’s short-term credit facilities and long-term debt agreements contain customary covenants and default provisions. As of December 31, 2010, there were no events of default under these covenants.

Convertible Securities

At December 31, 2010, Dominion had $202 million of outstanding contingent convertible senior notes that are convertible by holders into a combination of cash and shares of Dominion’s common stock under certain circumstances. The conversion feature requires that the principal amount of each note be repaid in cash, while amounts payable in excess of the principal amount will be paid in common stock. At issuance, the notes were valued at a conversion rate of 27.173 shares of common stock per $1,000 principal amount of senior notes, which represented a conversion price of $36.80. The conversion rate is subject to adjustment upon certain events such as subdivisions, splits, combinations of common stock or the issuance to all common stock holders of certain common stock rights, warrants or options and certain dividend increases. As of December 31, 2010, the conversion rate had been adjusted to 28.5032 shares, primarily due to individual dividend payments above the level paid at issuance.

The number of shares included in the denominator of the diluted EPS calculation is calculated as the net shares issuable for the reporting period based upon the average market price for the period. This results in an increase in the average shares outstanding used in the calculation of Dominion’s diluted EPS when the conversion price is lower than the average market price of Dominion’s common stock over the period, and results in no adjustment when the conversion price exceeds the average market price.

The senior notes are convertible by holders into a combination of cash and shares of Dominion’s common stock under any of the following circumstances:

(1)	The closing price of Dominion’s common stock equals 120% of the applicable conversion price or higher for at least 20 out of the last 30 consecutive trading days ending on the last trading day of the previous calendar quarter;

(2)	The senior notes are called for redemption by Dominion;

(3)	The occurrence of specified corporate transactions; or

(4)	The credit rating assigned to the senior notes by Moody’s is below Baa3 and by Standard & Poor’s is below BBB- or the ratings are discontinued for any reason.

During the first three quarters of 2010, the senior notes were not eligible for conversion. However, as of September 30, 2010, the closing price of Dominion’s common stock was equal to $42.24 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes were eligible for conversion during the fourth quarter of 2010. During 2010, less than $1 million of the contingent convertible senior notes were converted by holders. The senior notes were not eligible for conversion during 2009. As of December 31, 2010, the closing price of Dominion’s common stock was not equal to $42.10 per share or higher for at least 20 out of the last 30 consecutive trading days; therefore, the senior notes are not eligible for conversion during the first quarter of 2011. Beginning in 2007, the notes have been eligible for contingent interest if the average trading price as defined in the indenture equals or exceeds 120% of the principal amount of the senior notes. Holders have the right to require Dominion to purchase these senior notes for cash at 100% of the principal amount plus accrued interest in December 2011, 2013 or 2018, or if Dominion undergoes certain fundamental changes.

Junior Subordinated Notes Payable to Affiliated Trusts

In previous years, Dominion and Virginia Power established several subsidiary capital trusts, each as a finance subsidiary of the respective parent company, which hold 100% of the voting interests. The trusts sold trust preferred securities representing preferred beneficial interests and 97% beneficial ownership in the assets held by the trusts. In exchange for the funds realized from the sale of the trust preferred securities and common securities that represent the remaining 3% beneficial ownership interest in the assets held by the capital trusts, Dominion and Virginia Power issued various junior subordinated notes. The junior subordinated notes constitute 100% of each capital trust’s assets. Each trust must redeem its trust preferred securities when their respective junior subordinated notes are repaid at maturity or if redeemed prior to maturity.

In May 2008, Virginia Power repaid its $412 million 7.375% unsecured junior subordinated notes and redeemed all 16 million units of the $400 million 7.375% Virginia Power Capital Trust II

preferred securities due July 30, 2042. These securities were redeemed at a price of $25 per preferred security plus accrued and unpaid distributions.

The following table provides summary information about the trust preferred securities and junior subordinated notes outstanding as of December 31, 2010:


Date Established	Capital Trusts	Units		Rate			Trust Preferred Securities Amount		Common Securities Amount
		(thousands)					(millions)
December 1997	Dominion Resources Capital Trust I⁽¹⁾		250		7.83	%	$	250	$	7.7
January 2001	Dominion Resources Capital Trust III⁽²⁾		10		8.4	%		10		0.3

Junior subordinated notes/debentures held as assets by each capital trust were as follows:

(1)

$258 million—Dominion Resources, Inc. 7.83% Debentures due 12/1/2027.

(2)

$10 million—Dominion Resources, Inc. 8.4% Debentures due 1/15/2031.

The following table presents interest charges related to the Companies’ junior subordinated notes payable to affiliated trusts:


	2010		2009		2008
(millions)
Dominion	$	21	$	21	$	33
Virginia Power		—		—	$	12

Distribution payments on the trust preferred securities are considered to be fully and unconditionally guaranteed by the respective parent company that issued the debt instruments held by each trust when all of the related agreements are taken into consideration. Each guarantee agreement only provides for the guarantee of distribution payments on the relevant trust preferred securities to the extent that the trust has funds legally and immediately available to make distributions. The trust’s ability to pay amounts when they are due on the trust preferred securities is dependent solely upon the payment of amounts by Dominion when they are due on the junior subordinated notes. Dominion may defer interest payments on the junior subordinated notes on one or more occasions for up to five consecutive years and the related trusts must also defer distributions. If the payment on the junior subordinated notes is deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during any deferral period, Dominion may not make any payments on, redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the junior subordinated notes.

Enhanced Junior Subordinated Notes

In June 2006 and September 2006, Dominion issued $300 million of June 2006 hybrids and $500 million of September 2006 hybrids, respectively. The June 2006 hybrids will bear interest at 7.5% per year until June 30, 2016. Thereafter, they will bear interest at the three-month LIBOR plus 2.825%, reset quarterly. The September 2006 hybrids will bear interest at 6.3% per year until September 30, 2011. Thereafter, they will bear interest at the three-month LIBOR plus 2.3%, reset quarterly.

In June 2009, Dominion issued $685 million (including $60 million related to the underwriter’s option to purchase additional notes to cover over-allotments) of 8.375% June 2009 hybrids. The June 2009 hybrids are listed on the New York Stock Exchange under the symbol DRU.

In April 2010, Dominion purchased and cancelled $16 million of the September 2006 hybrids. These purchases were conducted in compliance with the RCCs.

Dominion may defer interest payments on the hybrids on one or more occasions for up to 10 consecutive years. If the interest payments on the hybrids are deferred, Dominion may not make distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments. Also, during the deferral period, Dominion may not make any payments on or redeem or repurchase any debt securities that are equal in right of payment with, or subordinated to, the hybrids.

NOTE 19. PREFERRED STOCK

Dominion is authorized to issue up to 20 million shares of preferred stock; however, none were issued and outstanding at December 31, 2010 or 2009.

Virginia Power is authorized to issue up to 10 million shares of preferred stock, $100 liquidation preference, and had 2.59 million preferred shares issued and outstanding at December 31, 2010 and 2009. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share would be entitled to receive $100 plus accrued cumulative dividends.

Holders of Virginia Power’s outstanding preferred stock are not entitled to voting rights except under certain provisions of the amended and restated articles of incorporation and related provisions of Virginia law restricting corporate action, upon default in dividends or in special statutory proceedings and as required by Virginia law (such as mergers, consolidations, sales of assets, dissolution and changes in voting rights or priorities of preferred stock).

Presented below are the series of Virginia Power preferred stock that were outstanding as of December 31, 2010:


Dividend	Issued and Outstanding Shares		Entitled Per Share Upon Liquidation
	(thousands)
$5.00		107	$	112.50
4.04		13		102.27
4.20		15		102.50
4.12		32		103.73
4.80		73		101.00
7.05		500		101.06	⁽¹⁾
6.98		600		101.05	⁽²⁾
Flex Money Market Preferred 12/02, Series A		1,250		100.00	⁽³⁾
Total		2,590

(1)

Through 7/31/2011; $100.71 commencing 8/1/2011; amounts decline in steps thereafter to $100.00 by 8/1/2013.

(2)

Through 8/31/2011; $100.70 commencing 9/1/2011; amounts decline in steps thereafter to $100.00 by 9/1/2013.

(3)

Dividend rate is 6.25% through 3/20/2011 after which the rate will be determined according to periodic auctions for periods established by Virginia Power at the time of the auction process.

NOTE 20. SHAREHOLDERS’ EQUITY

Issuance of Common Stock

DOMINION

During 2010, Dominion issued 2.3 million shares of common stock for cash proceeds of $74 million. The shares issued and cash proceeds received during 2010 were through Dominion Direct^®, employee savings plans and the exercise of employee stock options. In February 2010, Dominion began purchasing its common stock on the open market with proceeds received through Dominion Direct^® and employee savings plans, rather than having additional new common shares issued.

VIRGINIA POWER

In 2010, Virginia Power issued 33,013 shares of its common stock to Dominion for approximately $1 billion. The proceeds were used to pay down short-term demand note borrowings from Dominion.

Shares Reserved for Issuance

At December 31, 2010, Dominion had approximately 52 million shares reserved and available for issuance for Dominion Direct^®, employee stock awards, employee savings plans, director stock compensation plans and contingent convertible senior notes.

Repurchase of Common Stock

In March 2010, Dominion began repurchasing common shares in anticipation of proceeds from the sale of its Appalachian E&P operations. During 2010, Dominion repurchased 21.4 million shares of its common stock for approximately $900 million.

On January 28, 2011, Dominion announced that it intends to repurchase between $400 million and $700 million of common stock with cash tax savings resulting from the extension of the bonus depreciation allowance discussed in Note 6. In the first quarter of 2011, Dominion began repurchasing shares on the open market under this program.

Accumulated Other Comprehensive Income (Loss)

Presented in the table below is a summary of AOCI by component:


At December 31,	2010			2009
(millions)
Dominion
Net unrealized gains on derivatives-hedging activities, net of tax of $(27) and $(170)	$	51		$	281
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(142) and $(97)		226			151
Net unrecognized pension and other postretirement benefit costs, net of tax of $446 and $444		(607	)		(643	)
Total AOCI	$	(330	)	$	(211	)

Virginia Power
Net unrealized gains on derivatives-hedging activities, net of tax of $(2) and $(8)	$	4		$	13
Net unrealized gains on nuclear decommissioning trust funds, net of tax of $(13) and $(9)		20			13
Total AOCI	$	24		$	26

Stock-Based Awards

The 2005 Incentive Compensation Plan permits stock-based awards that include restricted stock, performance grants, goal-based stock, stock options, and stock appreciation rights. The Non-Employee Directors Plan permits grants of restricted stock and stock options. Under provisions of both plans, employees and non-employee directors may be granted options to purchase common stock at a price not less than its fair market value at the date of grant with a maximum term of eight years. Option terms are set at the discretion of the CGN Committee of the Board of Directors or the Board of Directors itself, as provided under each plan. At December 31, 2010, approximately 33 million shares were available for future grants under these plans.

Dominion measures and recognizes compensation expense relating to share-based payment transactions over the vesting period based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2010, 2009 and 2008 include $40 million, $44 million, and $46 million, respectively, of compensation costs and $15 million, $17 million, and $17 million, respectively, of income tax benefits related to Dominion’s stock-based compensation arrangements. Stock-based compensation cost is reported in other operations and maintenance expense in Dominion’s Consolidated Statements of Income. Benefits of tax deductions in excess of the compensation cost recognized for stock-based compensation (excess tax benefits) are classified as a financing cash flow. During the years ended December 31, 2010, 2009 and 2008, Dominion realized $10 million, $5 million, and $7 million, respectively, of excess tax benefits from the vesting of restricted stock awards and exercise of stock options.

STOCK OPTIONS

The following table provides a summary of changes in amounts of stock options outstanding as of and for the years ended December 31, 2010, 2009 and 2008. No options were granted under any plan in 2010, 2009 or 2008.


	Shares			Weighted - average Exercise Price		Weighted - average Remaining Contractual Life		Aggregated Intrinsic Value⁽¹⁾
	(thousands)					(years)		(millions)
Outstanding and exercisable at December 31, 2007		7,021		$	30.46
Exercised		(1,458	)	$	30.20			$	17
Forfeited/expired		(5	)	$	28.85
Outstanding and exercisable at December 31, 2008		5,558		$	30.53			$	30
Exercised		(1,706	)	$	28.93			$	10
Forfeited/expired		(30	)	$	28.89
Outstanding and exercisable at December 31, 2009		3,822		$	31.25			$	29
Exercised		(1,983	)	$	30.81			$	22
Forfeited/expired		(29	)	$	29.84
Outstanding and exercisable at December 31, 2010		1,810		$	31.76		1.1	$	20

(1)

Intrinsic value represents the difference between the exercise price of the option and the market value of Dominion’s stock.

Dominion issues new shares to satisfy stock option exercises. Dominion received cash proceeds from the exercise of stock options of approximately $63 million, $49 million, and $43 million in the years ended December 31, 2010, 2009 and 2008, respectively.

RESTRICTED STOCK

The fair value of Dominion’s restricted stock awards is equal to the market price of Dominion’s stock on the date of grant. New shares are issued for restricted stock awards on the date of grant and generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2010, 2009 and 2008:


	Shares			Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2007		2,014		$	35.31
Granted		546			40.99
Vested		(935	)		32.09
Cancelled and forfeited		(69	)		39.51
Converted from goal-based stock to restricted stock		200			34.77
Nonvested at December 31, 2008		1,756		$	38.55
Granted		533			33.84
Vested		(913	)		34.81
Cancelled and forfeited		(77	)		38.32
Converted from goal-based stock to restricted stock		185			44.18
Nonvested at December 31, 2009		1,484		$	39.88
Granted		463			38.80
Vested		(618	)		43.54
Cancelled and forfeited		(39	)		36.92
Converted from goal-based stock to restricted stock		186			40.84
Nonvested at December 31, 2010		1,476		$	38.20

As of December 31, 2010, unrecognized compensation cost related to nonvested restricted stock awards totaled $21 million and is expected to be recognized over a weighted-average period of 1.6 years. The fair value of restricted stock awards that vested was $26 million, $29 million, and $40 million in 2010, 2009 and 2008, respectively. Employees may elect to have shares of restricted stock withheld upon vesting to satisfy tax withholding obligations. The number of shares withheld will vary for each employee depending on the vesting date fair market value of Dominion stock and the applicable federal, state and local tax withholding rates.

GOAL-BASED STOCK

Goal-based stock awards have been granted to key contributors who are non-officer employees and to certain officers, who have not achieved a certain targeted level of share ownership, in lieu of cash-based performance grants. Current outstanding goal-based shares include awards granted in February 2009, April 2009 and February 2010.

The issuance of awards is based on the achievement of multiple performance metrics during a two-year period, including ROIC, BVP (for awards made in 2008 and 2009) and TSR relative to that of a peer group of companies. The actual number of

shares issued will vary between zero and 200% of targeted shares depending on the level of performance metrics achieved. The fair value of goal-based stock is equal to the market price of Dominion’s stock on the date of grant. Goal-based stock awards granted to key non-officer employees convert to restricted stock at the end of the two-year performance period and generally vest three years from the original grant date. Awards to officers vest at the end of the two-year performance period. All goal-based stock awards are settled by issuing new shares.

After the performance period for the April 2007 grants ended on December 31, 2008, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 127 thousand shares of the outstanding goal-based stock awards granted in April 2007 were converted to 185 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2010. For awards to officers, 27 thousand shares of the outstanding goal-based stock awards were converted to 38 thousand non-restricted shares and issued to the officers.

After the performance period for the April 2008 grants ended on December 31, 2009, the CGN Committee determined the actual performance against metrics established for those awards. For awards to key non-officer employees, 147 thousand shares of the outstanding goal-based stock awards granted in April 2008 were converted to 186 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2011. For awards to officers, 12 thousand shares of the outstanding goal-based stock awards were converted to 15 thousand non-restricted shares and issued to the officers.

The following table provides a summary of goal-based stock activity for the years ended December 31, 2010, 2009 and 2008:


	Targeted Number of Shares			Weighted - average Grant Date Fair Value
	(thousands)
Nonvested at December 31, 2007		289		$	39.16
Granted		164			40.97
Vested		(1	)		43.78
Cancelled and forfeited		(7	)		43.33
Converted from goal-based stock to restricted stock		(130	)		34.77
Nonvested at December 31, 2008		315		$	42.56
Granted		165			31.43
Vested		(28	)		44.38
Cancelled and forfeited		(2	)		37.24
Converted from goal-based stock to restricted stock		(127	)		44.18
Nonvested at December 31, 2009		323		$	36.12
Granted		9			37.46
Vested		(16	)		39.31
Cancelled and forfeited		(8	)		30.99
Converted from goal-based stock to restricted stock		(147	)		40.84
Nonvested at December 31, 2010		161		$	31.79

At December 31, 2010, the targeted number of shares expected to be issued under the February 2009, April 2009, and February 2010 awards was approximately 161 thousand. In January 2011, the CGN Committee determined the actual performance against metrics established for the February 2009 and April

2009 awards with a performance period that ended December 31, 2010. Based on that determination, the total number of shares to be issued under the goal-based stock awards was approximately 202 thousand.

As of December 31, 2010, unrecognized compensation cost related to nonvested goal-based stock awards totaled $2 million and is expected to be recognized over a weighted-average period of 1.1 years.

CASH-BASED PERFORMANCE GRANT

Cash-based performance grants are made to Dominion’s officers under Dominion’s LTIP. The actual payout of cash-based performance grants will vary between zero and 200% of the targeted amount based on the level of performance metrics achieved.

The targeted amount of the cash-based performance grant made to officers in April 2007 was $11 million, but the actual payout of the award in February 2009 determined by the CGN Committee was $16 million, based on the level of performance metrics achieved.

The targeted amount of the cash-based performance grant made to officers in April 2008 was $12 million, but the actual payout of the award in February 2010 determined by the CGN Committee was $15 million, based on the level of performance metrics achieved. At December 31, 2009, a liability of $15 million had been accrued for this award.

In February 2009, a cash-based performance grant was made to officers. A portion of the grant, representing the $11 million targeted amount as of December 31, 2010, was paid in December 2010, based on the achievement of three performance metrics during 2009 and 2010: ROIC, BVP and TSR relative to that of a peer group of companies. The total expected award under the grant is $14 million and the remaining portion of the grant will be paid by March 15, 2011. At December 31, 2010, a liability of $3 million had been accrued for the remaining portion of the award.

In February 2010, a cash-based performance grant was made to officers. Payout of the performance grant will occur by March 15, 2012 based on the achievement of two performance metrics during 2010 and 2011: ROIC and TSR relative to that of a peer group of companies. At December 31, 2010, the targeted amount of the grant was $12 million and a liability of $6 million had been accrued for this award.

NOTE 21. DIVIDEND RESTRICTIONS

Certain agreements associated with Dominion’s and Virginia Power’s credit facilities contain restrictions on the ratio of debt to total capitalization. These limitations did not restrict Dominion’s or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2010.

See Note 18 for a description of potential restrictions on dividend payments by Dominion in connection with the deferral of interest payments on junior subordinated notes.

NOTE 22. EMPLOYEE BENEFIT PLANS

DOMINION

Dominion provides certain benefits to eligible active employees, retirees and qualifying dependents. Under the terms of its benefit plans, Dominion reserves the right to change, modify or terminate the plans. From time to time in the past, benefits have changed, and some of these changes have reduced benefits.

Dominion maintains qualified noncontributory defined benefit pension plans covering virtually all employees. Retirement benefits are based primarily on years of service, age and the employee’s compensation. Dominion’s funding policy is to contribute annually an amount that is in accordance with the provisions of ERISA. The pension program also provides benefits to certain retired executives under a company-sponsored nonqualified employee benefit plan. The nonqualified plan is funded through contributions to a grantor trust.

Dominion provides retiree healthcare and life insurance benefits with annual employee premiums based on several factors such as age, retirement date and years of service. In January 2011, Dominion amended its retiree healthcare and life benefits to change the eligibility age for the majority of nonunion employees from 55 with 10 years of service to 58 with 10 years of service, resulting in an approximately $71 million reduction to the other postretirement benefit plan obligation. The eligibility requirements for nonunion employees hired on or after January 1, 2008, who benefit under the Retiree Medical Account design, as well as for union employees are not affected by this plan design change.

Pension and other postretirement benefit costs are affected by employee demographics (including age, compensation levels and years of service), the level of contributions made to the plans and earnings on plan assets. These costs may also be affected by changes in key assumptions, including expected long-term rates of return on plan assets, discount rates, healthcare cost trend rates and the rate of compensation increases.

Dominion uses December 31 as the measurement date for all of its employee benefit plans. Dominion uses the market-related value of pension plan assets to determine the expected return on plan assets, a component of net periodic pension cost. The market-related value recognizes changes in fair value on a straight-line basis over a four-year period, which reduces year-to-year volatility. Changes in fair value are measured as the difference between the expected and actual plan asset returns, including dividends, interest and realized and unrealized investment gains and losses. Since the market-related value recognizes changes in fair value over a four-year period, the future market-related value of pension plan assets will be impacted as previously unrecognized changes in fair value are recognized.

Dominion’s pension and other postretirement benefit plans hold investments in trusts to fund employee benefit payments. Aggregate actual returns for Dominion’s pension and other postretirement plan assets were $624 million in 2010 and $777 million in 2009, versus expected returns of $479 million and $462 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of cash to be contributed to the employee benefit plans.

The Medicare Act introduced a federal subsidy to sponsors of retiree healthcare benefit plans that provide a prescription drug benefit that is at least actuarially equivalent to Medicare Part D. Dominion determined that the prescription drug benefit offered under its other postretirement benefit plans is at least actuarially equivalent to Medicare Part D. In 2010 and 2009, Dominion received a federal subsidy of $5 million and $4 million, respectively, and expects to continue to receive the subsidy offered under the Medicare Act.

The following table summarizes the changes in Dominion’s pension plan and other postretirement benefit plan obligations and plan assets and includes a statement of the plans’ funded status:


	Pension Benefits						Other Postretirement Benefits
Year Ended December 31,	2010			2009			2010			2009
(millions, except percentages)
Changes in benefit obligation:
Benefit obligation at beginning of year	$	4,126		$	3,893		$	1,555		$	1,554
Service cost		102			106			56			60
Interest cost		266			250			101			100
Benefits paid		(211	)		(179	)		(82	)		(77	)
Actuarial (gains) losses during the year		210			54			36			(85	)
Transfer⁽¹⁾		(48	)		—			—			—
Plan amendments		1			1			—			(1	)
Settlements and curtailments⁽²⁾		34			1			35			—
Special termination benefits⁽³⁾		10			—			1			—
Medicare Part D reimbursement		—			—			5			4
Benefit obligation at end of year	$	4,490		$	4,126		$	1,707		$	1,555
Changes in fair value of plan assets:
Fair value of plan assets at beginning of year	$	4,226		$	3,757		$	918		$	747
Actual return on plan assets		532			633			92			144
Employer contributions		665			15			56			64
Benefits paid		(211	)		(179	)		(35	)		(37	)
Transfer⁽¹⁾		(106	)		—			—			—
Fair value of plan assets at end of year	$	5,106		$	4,226		$	1,031		$	918
Funded status at end of year	$	616		$	100		$	(676	)	$	(637	)
Amounts recognized in the Consolidated Balance Sheets at December 31:
Assets held for sale⁽⁴⁾	$	—		$	47		$	—		$	—
Noncurrent pension and other postretirement benefit assets		710			695			2			7
Liabilities held for sale⁽⁴⁾		—			—			—			(11	)
Other current liabilities		(4	)		(13	)		(3	)		(2	)
Noncurrent pension and other postretirement benefit liabilities		(90	)		(629	)		(675	)		(631	)
Net amount recognized	$	616		$	100		$	(676	)	$	(637	)
Significant assumptions used to determine benefit obligations as of December 31:
Discount rate		5.90	%		6.60	%		5.90	%		6.60	%
Weighted average rate of increase for compensation		4.61	%		4.76	%		4.62	%		4.79	%

(1)

Represents transfer of pension plan assets and obligation for all active Peoples employees as of February 1, 2010. See Note 4 for more information on the sale of Peoples completed in February 2010.

(2)

Relates to the sales of Peoples and Dominion’s Appalachian E&P operations and a workforce reduction program.

(3)

Represents a one-time special termination benefit for certain employees in connection with a workforce reduction program.

(4)

Represents pension plan assets classified as assets held for sale and other postretirement benefit plan obligations classified as liabilities held for sale for Peoples in Dominion’s Consolidated Balance Sheets.

The ABO for all of Dominion’s defined benefit pension plans was $4.1 billion and $3.6 billion at December 31, 2010 and 2009, respectively.

Under its funding policies, Dominion evaluates plan funding requirements annually, usually in the fourth quarter after receiving updated plan information from its actuary. Based on the funded status of each plan and other factors, Dominion determines the amount of contributions for the current year, if any, at that time. During 2010, Dominion contributed $650 million to its qualified defined benefit pension plans. No contributions to its qualified defined benefit pension plans are currently expected in 2011. Certain regulatory authorities have held that amounts recovered in utility customers’ rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, certain of Dominion’s subsidiaries fund other postretirement benefit costs through VEBAs. Dominion’s remaining subsidiaries do not prefund other postretirement benefit costs but instead pay claims as presented. Dominion expects to contribute approximately $22 million to the Dominion VEBAs in 2011.

Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2011.

The following table provides information on the benefit obligations and fair value of plan assets for plans with a benefit obligation in excess of plan assets:


	Pension Benefits					Other Postretirement Benefits
As of December 31,	2010			2009		2010		2009
(millions)
Benefit obligation	$	121	⁽¹⁾	$	3,537	$	1,583	$	1,430
Fair value of plan assets		27	⁽¹⁾		2,902		905		786

(1)

The decrease reflects cash contributions to the pension plans during 2010 and the merger of the Dominion Peoples Gas Union Pension Plan into the DPP at December 31, 2010.

The following table provides information on the ABO and fair value of plan assets for pension plans with an ABO in excess of plan assets:


As of December 31,	2010			2009
(millions)
Accumulated benefit obligation	$	80	⁽¹⁾	$	3,085
Fair value of plan assets		—	⁽¹⁾		2,902

(1)

The decrease reflects cash contributions to the pension plans during 2010.

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:


	Estimated Future Benefit Payments
	Pension Benefits		Other Postretirement Benefits
(millions)
2011	$	219	$	101
2012		226		106
2013		234		111
2014		246		116
2015		271		121
2016-2020		1,636		681

The above benefit payments for other postretirement benefit plans are expected to be offset by Medicare Part D subsidies of approximately $6 million each in 2011 and 2012, $7 million each in 2013 and 2014, $8 million in 2015 and $50 million during the period 2016 through 2020.

Dominion’s overall objective for investing its pension and other postretirement plan assets is to achieve the best possible long-term rates of return commensurate with prudent levels of risk. To minimize risk, funds are broadly diversified among asset classes, investment strategies and investment advisors. The strategic target asset allocations for its pension funds are 28% U.S. equity, 18% non-U.S. equity, 33% fixed income, 3% real estate and 18% other alternative investments. U.S. equity includes investments in large-cap, mid-cap and small-cap companies

located in the United States. Non-U.S. equity includes investments in large-cap companies located outside of the United States including both developed and emerging markets. Fixed income includes corporate debt instruments of companies from diversified industries and U.S. Treasuries. The U.S. equity, non-U.S. equity and fixed income investments are in individual securities as well as mutual funds. Real estate includes equity REITs and investments in partnerships. Other alternative investments include partnership investments in private equity, debt and hedge funds that follow several different strategies.

Strategic investment policies are established for each of Dominion’s prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from the plans’ strategic allocation are a function of Dominion’s assessments regarding short-term risk and reward opportunities in the capital markets and/or short-term market movements which result in the plans’ actual asset allocations varying from the strategic target asset allocations. Through periodic rebalancing, actual allocations are brought back in line with the target. Financial derivatives may be used to obtain or manage market exposures and to hedge assets and liabilities.

For fair value measurement policies and procedures related to pension and other postretirement benefit plan assets, see Note 7.

The fair values of Dominion’s pension plan assets by asset category are as follows:

The fair values of Dominion’s other postretirement plan assets by asset category are as follows:

The following table presents the changes in Dominion’s pension plan assets that are measured at fair value and included in the Level 3 fair value category:

The following table presents the changes in Dominion’s other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:

The components of the provision for net periodic benefit (credit) cost and amounts recognized in other comprehensive income and regulatory assets and liabilities are as follows:

The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost are as follows:


	Pension Benefits				Other Postretirement Benefits
At December 31,	2010		2009		2010			2009
(millions)
Net actuarial loss	$	1,773	$	1,788	$	268		$	271
Prior service (credit) cost		17		19		(28	)		(36	)
Total⁽¹⁾	$	1,790	$	1,807	$	240		$	235

(1)

As of December 31, 2010, of the $1.8 billion and $240 million related to pension benefits and other postretirement benefits, $978 million and $75 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities. As of December 31, 2009, of the $1.8 billion and $235 million related to pension benefits and other postretirement benefits, $1 billion and $87 million, respectively, are included in AOCI, with the remainder included in regulatory assets and liabilities.

The following table provides the components of AOCI and regulatory assets and liabilities as of December 31, 2010 that are expected to be amortized as components of periodic benefit cost in 2011:


	Pension Benefits		Other Postretirement Benefits
(millions)
Net actuarial loss	$	96	$	12
Prior service (credit) cost		3		(6	)

Dominion determines the expected long-term rates of return on plan assets for its pension plans and other postretirement benefit plans by using a combination of:

•

Historical return analysis to determine expected future risk premiums, asset volatilities and correlations;

•

Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices;

•

Expected inflation and risk-free interest rate assumptions; and

•

Investment allocation of plan assets.

Dominion develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions.

Dominion determines discount rates from analyses of AA/Aa rated bonds with cash flows matching the expected payments to be made under its plans.

Assumed healthcare cost trend rates have a significant effect on the amounts reported for Dominion’s retiree healthcare plans. A one percentage point change in assumed healthcare cost trend rates would have had the following effects:


	Other Postretirement Benefits
	One percentage point increase		One percentage point decrease
(millions)
Effect on total of service and interest cost components for 2010	$	23	$	(20	)
Effect on other postretirement benefit obligation at December 31, 2010		217		(171	)

In addition, Dominion sponsors defined contribution employee savings plans. During 2010, 2009 and 2008, Dominion recognized $39 million, $42 million and $39 million, respectively, as contributions to these plans.

VIRGINIA POWER

Virginia Power participates in a defined benefit pension plan sponsored by Dominion. Benefits payable under the plan are based primarily on years of service, age and the employee’s compensation. As a participating employer, Virginia Power is subject to Dominion’s funding policy, which is to contribute annually an amount that is in accordance with the provisions of ERISA. During 2010, Virginia Power contributed $302 million to the defined benefit pension plan. Virginia Power’s net periodic pension cost related to this pension plan was $84 million, $48 million and $32 million in 2010, 2009 and 2008, respectively. The 2010 net periodic pension cost includes the impact of a settlement and curtailment as well as a one-time special termination benefit for certain employees in connection with a workforce reduction program. Employee compensation is the basis for determining Virginia Power’s share of total pension costs.

Virginia Power participates in a plan that provides certain retiree healthcare and life insurance benefits to multiple Dominion subsidiaries. Annual employee premiums are based on several factors such as age, retirement date and years of service. Virginia Power’s net periodic benefit cost related to this plan was $59 million, $55 million and $33 million in 2010, 2009 and 2008, respectively. Employee headcount is the basis for determining Virginia Power’s share of total other postretirement benefit costs.

Certain regulatory authorities have held that amounts recovered in rates for other postretirement benefits, in excess of benefits actually paid during the year, must be deposited in trust funds dedicated for the sole purpose of paying such benefits. Accordingly, Virginia Power funds other postretirement benefit costs through a VEBA. Virginia Power’s contributions to the VEBA were $35 million, $34 million and $15 million in 2010, 2009 and 2008, respectively. Virginia Power expects to contribute approximately $4 million to the VEBA in 2011.

Dominion holds investments in trusts to fund employee benefit payments for its pension and other postretirement benefit plans, in which Virginia Power’s employees participate. Any investment-related declines in these trusts will result in future increases in the periodic cost recognized for such employee benefit plans and will be included in the determination of the amount of

cash that Virginia Power will provide to Dominion for its share of employee benefit plan contributions.

Virginia Power also participates in Dominion-sponsored defined contribution employee savings plans that cover substantially all employees. Employer matching contributions of $14 million were incurred in each of 2010, 2009 and 2008.

NOTE 23. COMMITMENTS AND CONTINGENCIES

As the result of issues generated in the ordinary course of business, Dominion and Virginia Power are involved in legal, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies, some of which involve substantial amounts of money. The ultimate outcome of such proceedings cannot be predicted at this time; however, for current proceedings not specifically reported herein, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on Dominion’s or Virginia Power’s financial position, liquidity or results of operations.

Long-Term Purchase Agreements

At December 31, 2010, Virginia Power had the following long-term commitments that are noncancelable or are cancelable only under certain conditions, and that third parties have used to secure financing for the facilities that will provide the contracted goods or services:


	2011		2012		2013		2014		2015		Thereafter		Total
(millions)
Purchased electric capacity⁽¹⁾	$	342	$	347	$	351	$	358	$	338	$	779	$	2,515

(1)

Commitments represent estimated amounts payable for capacity under power purchase contracts with qualifying facilities and independent power producers, the last of which ends in 2021. Capacity payments under the contracts are generally based on fixed dollar amounts per month, subject to escalation using broad-based economic indices. At December 31, 2010, the present value of Virginia Power’s total commitment for capacity payments is $1.8 billion. Capacity payments totaled $344 million, $356 million, and $379 million, and energy payments totaled $303 million, $254 million, and $372 million for 2010, 2009 and 2008, respectively.

Lease Commitments

Dominion and Virginia Power lease various facilities, vehicles and equipment primarily under operating leases. Payments under certain leases are escalated based on an index such as the consumer price index. Future minimum lease payments under noncancelable operating and capital leases that have initial or remaining lease terms in excess of one year as of December 31, 2010 are as follows:


	2011		2012		2013		2014		2015		Thereafter		Total
(millions)
Dominion	$	184	$	174	$	138	$	60	$	48	$	193	$	797

Virginia Power	$	36	$	28	$	17	$	14	$	12	$	23	$	130

Rental expense for Dominion totaled $171 million, $172 million, and $160 million for 2010, 2009 and 2008, respectively. Rental expense for Virginia Power totaled $50 million, $49 mil-

lion, and $39 million for 2010, 2009, and 2008, respectively. The majority of rental expense is reflected in other operations and maintenance expense.

Dominion leases Fairless, which began commercial operations in June 2004. During construction, Dominion acted as the construction agent for the lessor, controlled the design and construction of the facility and has since been reimbursed for all project costs ($898 million) advanced to the lessor. Dominion makes annual lease payments of $53 million that are reflected in the lease commitments table. The lease expires in 2013 and at that time, Dominion may renew the lease at negotiated amounts based on original project costs and current market conditions, subject to lessor approval; purchase Fairless at its original construction cost plus 51% of any appraised value in excess of original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of the original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events.

Environmental Matters

AIR

The CAA is a comprehensive program utilizing a broad range of regulatory tools to protect and preserve the nation’s air quality. At a minimum, states are required to establish regulatory programs to address all requirements of the CAA. However, states may choose to develop regulatory programs that are more restrictive. Many of Dominion’s and Virginia Power’s facilities are subject to the CAA’s permitting and other requirements.

In May 2010, 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 Brayton Point and Salem Harbor. Dominion submitted its response to this request in November 2010 and cannot predict the outcome of this matter.

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 State Line and Kincaid. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April 2009, Dominion received a Notice and Finding of Violations from the EPA claiming violations of the CAA New Source Review requirements, New Source Performance Standards, the Title V permit program and the stations’ respective State Implementation Plans. The Notice states that the EPA may issue an order requiring compliance with the relevant CAA provisions and may seek injunctive relief and/or civil penalties, all pursuant to the EPA’s enforcement

authority under the CAA. Dominion cannot predict the outcome of this matter. However, an adverse resolution could have a material effect on future results of operations and/or cash flows.

In March 2005, the EPA promulgated regulations finalizing CAIR and CAMR. In February 2008, the Court of Appeals for the District of Columbia Circuit issued a ruling vacating CAMR. The EPA is proceeding with the development of a MACT rulemaking for coal and oil-fired electric utility steam generating units. These rules could require significant reductions in mercury and other HAPs from electric generation facilities. It should be noted that Dominion continues to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that were largely unaffected by the CAMR ruling.

In July 2008, the Court issued a ruling vacating CAIR. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA. The CAIR rules remain in effect until such time that the EPA develops and implements new rulemaking addressing the issues identified by the Court. In July 2010, the EPA announced a proposed new rule, called the Transport Rule, which will eventually replace CAIR, and, as proposed, requires significant reductions in SO₂ and NO_X emissions.

The EPA has finalized rules establishing a new 1-hour NAAQS for NO₂ (January 2010) and a new 1-hour NAAQS for SO₂ (June 2010), which could require additional NO_X and SO₂ controls in certain areas where the Companies operate. Until the states have developed implementation plans for these standards, the impact on Dominion’s or Virginia Power’s facilities that emit NO_X and SO₂ is uncertain. However, based on a preliminary assessment, Dominion has determined that the new 1-hour SO₂ NAAQS will likely require significant future capital expenditures at State Line, and, accordingly, recorded an impairment charge on this facility in the second quarter of 2010. In January 2010, the EPA also proposed a new, more stringent NAAQS for ozone. Until the rulemaking for the Transport Rule is complete and the states have developed implementation plans for the new NO₂, SO₂ and ozone standards, it is not possible to determine the impact on Dominion’s or Virginia Power’s facilities that emit NO_X and SO₂. The Companies cannot currently predict with certainty whether or to what extent the new rules will ultimately require additional controls, however, if significant expenditures are required, it could adversely affect Dominion’s results of operations, and Dominion’s and Virginia Power’s cash flows.

In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule. Although Dominion and Virginia Power anticipate that the emission reductions achieved through compliance with other CAA required programs will generally address this rule, additional emission reduction requirements may be imposed on the Companies’ facilities.

Implementation of projects to comply with SO₂, NO_X and mercury limitations, and other state emission control programs are ongoing and will be influenced by changes in the regulatory environment, availability of emission allowances and emission control technology. In response to federal and state regulatory requirements, Dominion and Virginia Power estimate that they will make capital expenditures at their affected generating facilities of approximately $2.4 billion and $2.0 billion, respectively, during the period 2011 through 2015.

In December 2010, the Virginia Department of Environmental Quality approved an air permit to construct the power station development project in Warren County, Virginia. In connection with the air permit process, Virginia Power reached an agreement with the National Park Service to permanently retire the North Branch power station, a 74 MW coal fired plant located in West Virginia, once the Warren County power station begins commercial operations.

In June 2010, the Conservation Law Foundation and Healthlink, Inc., filed a Complaint in the District Court of Massachusetts against Dominion Energy New England, Inc. alleging that Salem Harbor units 1, 2, 3, and 4 have been and are in violation of visible emissions standards and monitoring requirements of the Massachusetts State Implementation Plan and the station’s state and federal operating permits. Although Dominion cannot predict the outcome of this matter at this time, it is not expected to have a material effect on results of operations.

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, 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. In September 2009, the hazardous emissions air permit was amended by the Virginia Department of Environmental Quality to comply with the Richmond Circuit Court Order. The permit amendment does not impact the project. In October 2009, 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. In May 2010, the Court of Appeals affirmed the Circuit Court’s opinion in the appeal of the Virginia City Hybrid Energy Center’s air permit. SELC did not further appeal the Court of Appeals decision to the Supreme Court of Virginia.

WATER

The CWA is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. Dominion and Virginia Power must comply with all aspects of the CWA programs at their operating facilities. In July 2004, the EPA published regulations under CWA Section 316b that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. The EPA’s rule presented several compliance options. However, in January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision on an appeal of the regulations, remanding the rule to the EPA. In July 2007, the EPA suspended the regulations pending further rulemaking, consistent with the decision issued by the U.S. Court of Appeals for the Second Circuit. In November 2007, a number of industries appealed the lower court decision to the U.S. Supreme Court. In April 2008, the

U.S. Supreme Court granted the industry request to review the question of whether Section 316b of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. The U.S. Supreme Court ruled in April 2009 that the EPA has the authority to consider costs versus environmental benefits in selecting best technology available for reducing impacts of cooling water intakes at power stations. It is currently unknown how the EPA will interpret the ruling in its ongoing rulemaking activity addressing cooling water intakes as well as how the states will implement this decision. Dominion has sixteen facilities, including eight at Virginia Power, that are likely to be subject to these regulations. In November 2010, the EPA settled with the original litigants and agreed to publish a proposed rule no later than March 14, 2011 and a final rule no later than July 27, 2012. Dominion and Virginia Power cannot predict the outcome of the EPA regulatory processes, nor can they determine with any certainty what specific controls may be required.

In August 2006, the CDEP issued a notice of a Tentative Determination to renew the NPDES permit for Millstone, which included a draft copy of the revised permit. In October 2007, CDEP issued a report to the hearing officer for the tentative determination stating the agency’s intent to further revise the draft permit. In December 2007, the CDEP issued a new draft permit. An administrative hearing on the draft permit began in January 2009 and was completed in February 2009. In February 2010, the hearing officer issued a proposed final decision, recommending that the CDEP Commissioner issue the revised draft permit without change. In September 2010, the permit was reissued under the CWA. The conditions of the permit require an evaluation of control technologies that could result in additional expenditures in the future, however Dominion cannot currently predict the outcome of this evaluation. In October 2010, the permit issuance was appealed to the state court by a private plaintiff. The permit is expected to remain in effect during the appeal.

In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Currently, Dominion estimates the total cost to install these cooling towers at approximately $600 million, with remaining expenditures of $354 million included in its planned capital expenditures through 2012.

In October 2007, the VSWCB issued a renewed VPDES permit for North Anna. BREDL, and other persons, appealed the VSWCB’s decision to the Richmond Circuit Court, challenging several permit provisions related to North Anna’s discharge of cooling water. In February 2009, the court ruled that the VSWCB was required to regulate the thermal discharge from North Anna into the waste heat treatment facility. Virginia Power filed a motion for reconsideration with the court in February 2009, which was denied. The final order was issued by the court in September 2009. The court’s order allows North Anna to continue to operate pursuant to the currently issued VPDES permit. In October 2009, Virginia Power filed a Notice of Appeal of the court’s Order with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. In June 2010,

the Virginia Court of Appeals reversed the Richmond Circuit Court’s September 2009 order. The Virginia Court of Appeals held that the lower court had applied the wrong standard of review, and that the VSWCB’s determination not to regulate the station’s thermal discharge into the waste heat treatment facility was lawful. In July 2010, BREDL and the other original appellants filed a petition for appeal to the Supreme Court of Virginia requesting that it review the Court of Appeals’ decision. In December 2010, the Supreme Court of Virginia granted BREDL’s petition. Briefing on the merits of the case will occur during the first quarter of 2011. Until the appeals process is complete and any revised permit is issued, it is not possible to predict with certainty any financial impact that may result, however, an adverse resolution could have a material effect on Virginia Power’s cash flows.

SOLID AND HAZARDOUS WASTE

The CERCLA, as amended, provides for immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under the CERCLA as amended, generators and transporters of hazardous substances, as well as past and present owners and operators of contaminated sites, can be strictly, jointly and severally liable for the cost of cleanup. These potentially responsible parties can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

From time to time, Dominion or Virginia Power may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or conduct the remedial investigation and action itself and then seek reimbursement from the potentially responsible parties. Each party can be held jointly, severally and strictly liable for the cleanup costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion or Virginia Power may be responsible for the costs of remedial investigation and actions under the Superfund law or other laws or regulations regarding the remediation of waste. The Companies do not believe that any currently identified sites will result in significant liabilities.

Dominion has determined that it is associated with 17 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plant sites have indicated that those sites contain coal tar and other potentially harmful materials. None of the 17 former sites with which Dominion is associated is under investigation by any state or federal environmental agency. At one of the former sites Dominion is conducting a state-approved post closure groundwater monitoring program and an environmental land use restriction has been recorded. Another site has been accepted into a state-based voluntary remediation program and Dominion has not yet estimated the future remediation costs. It is not known to what degree the other former sites may contain environmental contamination. Dominion

is not able to estimate the cost, if any, that may be required for the possible remediation of these other sites.

In June 2010, the EPA proposed federal regulations under the RCRA for management of coal combustion by-products generated by power plants. The EPA is considering two possible options for the regulation of coal combustion by-products, both of which fall under the RCRA. Under the first proposal, the EPA would classify these by-products as special wastes subject to regulation under subtitle C, the hazardous waste provisions of the RCRA, when destined for disposal at landfills or surface impoundments. Under the second proposal, the EPA would regulate coal combustion by-products under subtitle D of the RCRA, the section for non-hazardous wastes. While the Companies cannot currently predict the outcome of this matter, regulation under either option will affect Dominion’s and Virginia Power’s onsite disposal facilities and coal combustion by-product management practices, and potentially require material investments.

CLIMATE CHANGE LEGISLATION AND REGULATION

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.” On April 1, 2010, the EPA and the Department of Transportation’s National Highway Safety Administration announced a joint final rule establishing a program that will dramatically reduce GHG emissions and improve fuel economy for new cars and trucks sold in the United States. These rules took effect in January 2011 and established GHG emissions as regulated pollutants under the CAA. In May 2010, the EPA issued the Final Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule that, combined with these prior actions, will require Dominion and Virginia Power to obtain permits for GHG emissions for new and modified facilities over certain size thresholds, and meet best available control technology for GHG emissions beginning in 2011. The EPA has issued draft guidance for GHG permitting, including best available control technology. EPA has also announced a schedule for proposing regulations of GHG emissions under the New Source Performance Standards that would apply to new and existing electric generating units. Also, the Companies expect continued regulatory action at the state level on the regulation of GHG emissions in the future. Any of these new or contemplated regulations above may affect capital costs, or create significant permitting delays, for new or modified facilities that emit GHGs.

There are other legislative proposals that may be considered that would have an indirect impact on GHG emissions. There is the potential for the Congress to consider a mandatory Clean Energy Standard or to promote greater energy efficiency through early retirements of coal-fired power plants.

In addition to possible federal action, some regions and states in which Dominion and Virginia Power operate have already adopted or may adopt GHG emission reduction programs. For example, the Virginia Energy Plan, released by the Governor of Virginia in September 2007, includes a goal of reducing GHG emissions state-wide back to 2000 levels by 2025. The Governor formed a Commission on Climate Change to develop a plan to achieve this goal. In November 2008, the Commission formulated its recommendations to the Governor.

In July 2008, Massachusetts passed the GWSA. Among other provisions, the GWSA sets economy-wide GHG emissions reduction goals for Massachusetts, including reductions of 10% to 25% below 1990 levels by 2020, interim goals for 2030 and 2040 and reductions of 80% below 1990 levels by 2050. Regulations requiring the implementation of the GWSA have not yet been proposed. Dominion operates two coal/oil-fired generating power stations in Massachusetts and acts as a retail electric supplier in Massachusetts and all of these entities are subject to the implementation of the GWSA.

Additionally, Massachusetts, Rhode Island and Connecticut, among other states, have joined the RGGI, a multi-state effort to reduce CO₂ emissions in the Northeast implemented through state specific regulations. Under the initiative, aggregate CO₂ emissions from power plants in participating states are required to be stabilized at current levels from 2009 to 2015. Further reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO₂ emissions. During 2011 and possibly continuing through 2012, RGGI will undergo a program review which could impact regulations and implementation of RGGI. The impact of this program review on Dominion’s fossil fired generation operations in RGGI states is unknown at this time.

Three of Dominion’s facilities, Brayton Point, Salem Harbor and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that Dominion cover each ton of CO₂ direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. Dominion participated in RGGI allowance auctions to date and has procured allowances to meet its estimated compliance requirements under RGGI for 2009 and 2010 and partially for 2011. Dominion does not expect these allowances to have a material impact on its results of operations or financial condition.

In December 2009, the governors of 11 Northeast and mid-Atlantic states, including Connecticut, Maryland, Massachusetts, New York, Pennsylvania, and Rhode Island (RGGI states plus Pennsylvania) signed a memorandum of understanding committing their states toward developing a low carbon fuel standard to reduce GHG emissions from vehicles. The memorandum of understanding establishes a process to develop a regional framework by 2011 and examine the economic impacts of a low carbon fuel standard program.

The U.S. is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change that became effective for signatories on February 16, 2005. The Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2009 United Nations Climate Change Conference in Copenhagen, Denmark, the Copenhagen Accord was adopted, which includes a collection of non-binding, voluntary actions by various countries, including the U.S, to keep the increase in global mean temperature below 2 degrees Celsius. It does not include specific emissions targets, but calls for industrial nations to offer up emissions reduction targets for 2020. The U.S. is expected to participate in this process.

Nuclear Operations

NUCLEAR DECOMMISSIONING—MINIMUM FINANCIAL ASSURANCE

The NRC requires nuclear power plant owners to annually update minimum financial assurance amounts for the future decommissioning of their nuclear facilities. The 2010 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, was $3.1 billion and $1.8 billion, respectively, and has been satisfied by a combination of the funds being collected and deposited in the nuclear decommissioning trusts and the real annual rate of return growth of the funds allowed by the NRC. The 2010 NRC minimum financial assurance amounts shown were calculated using September 30, 2010 U.S. Bureau of Labor Statistics indices. The final NRC minimum financial assurance amounts that will be filed with the NRC in March 2011 will most likely be based on December 31, 2010 indices. Dominion does not anticipate a material difference between the NRC minimum financial assurance amounts shown and the final NRC minimum financial amounts to be filed with the NRC. Dominion believes that the amounts currently available in its decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Virginia Power also believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects a positive long-term outlook for trust fund investment returns as the units will not be decommissioned for decades. Dominion and 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.

NUCLEAR INSURANCE

The Price-Anderson Act provides the public up to $12.6 billion of liability protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Amendments Act of 1988 allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $375 million of coverage from commercial insurance pools for each reactor site with the remainder provided through a mandatory industry risk-sharing program. In the event of a nuclear incident at any licensed nuclear reactor in the U.S., the Companies could be assessed up to $118 million for each of their licensed reactors not to exceed $18 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed.

The current level of property insurance coverage for Dominion’s and Virginia Power’s nuclear units is as follows:


	Coverage
(billions)
Dominion
Millstone	$	2.75
Kewaunee		1.80

Virginia Power
Surry	$	2.55
North Anna		2.55

The Companies’ coverage exceeds the NRC minimum requirement for nuclear power plant licensees of $1.06 billion per reactor site and includes coverage for premature decommissioning and functional total loss. The NRC requires that the proceeds from this insurance be used first, to return the reactor to and maintain it in a safe and stable condition and second, to decontaminate the reactor and station site in accordance with a plan approved by the NRC. Nuclear property insurance is provided by NEIL, a mutual insurance company, and is subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance company. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $77 million and $39 million, respectively. Based on the severity of the incident, the board of directors of the nuclear insurer has the discretion to lower or eliminate the maximum retrospective premium assessment. Dominion and Virginia Power have the financial responsibility for any losses that exceed the limits or for which insurance proceeds are not available because they must first be used for stabilization and decontamination.

Dominion and Virginia Power also purchase insurance from NEIL to mitigate certain expenses, including replacement power costs, associated with the prolonged outage of a nuclear unit due to direct physical damage. Under this program, the Companies are subject to a retrospective premium assessment for any policy year in which losses exceed funds available to NEIL. Dominion’s and Virginia Power’s maximum retrospective premium assessment for the current policy period is $32 million and $18 million, respectively.

ODEC, a part owner of North Anna, and Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation, part owners of Millstone’s Unit 3, are responsible to Dominion and Virginia Power for their share of the nuclear decommissioning obligation and insurance premiums on applicable units, including any retrospective premium assessments and any losses not covered by insurance.

SPENT NUCLEAR FUEL

request to stay the appeal. In May 2010, the stay was lifted, and the government’s initial brief in the appeal was filed in June 2010. The issues raised by the government on appeal pertain to the damages awarded to Dominion for Millstone. The government did not take issue with the damages awarded to Virginia Power for Surry or North Anna. As a result, Virginia Power recognized a receivable in the amount of $174 million, largely offset against property, plant and equipment and regulatory assets and liabilities, representing certain spent nuclear fuel-related costs incurred through June 30, 2010. Briefing on the appeal was concluded in September 2010 and oral argument took place before the Federal Circuit in January 2011. Payment of any damages will not occur until the appeal process has been resolved.

The Companies will continue to manage their spent fuel until it is accepted by the DOE.

Virginia Power and Kewaunee continue to recognize receivables for certain spent nuclear fuel-related costs that are probable of recovery from the DOE.

Guarantees, Surety Bonds and Letters of Credit

DOMINION

At December 31, 2010, Dominion had issued $131 million of guarantees, primarily to support equity method investees. No significant amounts related to these guarantees have been recorded. As of December 31, 2010, Dominion’s exposure under these guarantees was $54 million, primarily related to certain reserve requirements associated with non-recourse financing. During the first quarter of 2010, Dominion’s $165 million limited-scope guarantee and indemnification for one-half of NedPower’s project-level financing, relating to litigation seeking to halt the NedPower wind farm, was formally terminated with the consent of NedPower’s lenders as a result of the dismissal by the applicable court of such litigation pursuant to an agreed dismissal order.

In addition to the above guarantees, Dominion and its partners, Shell and BP, may be required to make additional periodic equity contributions to NedPower and Fowler Ridge in connection with certain funding requirements associated with their respective non-recourse financings. As of December 31, 2010, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $144 million through 2019 and its maximum annual future contributions could range from approximately $16 million to $19 million. Dominion expects the operating cash flows from these projects to be sufficient to meet their financing requirements.

Dominion also enters into guarantee arrangements on behalf of its consolidated subsidiaries, primarily to facilitate their commercial transactions with third parties. To the extent that a liability subject to a guarantee has been incurred by one of Dominion’s consolidated subsidiaries, that liability is included in its Consolidated Financial Statements. Dominion is not required to recognize liabilities for guarantees issued on behalf of its subsidiaries unless it becomes probable that it will have to perform under the guarantees. Terms of the guarantees typically end once

obligations have been paid. Dominion currently believes it is unlikely that it would be required to perform or otherwise incur any losses associated with guarantees of its subsidiaries’ obligations.

At December 31, 2010, Dominion had issued the following subsidiary guarantees:


	Stated Limit		Value⁽¹⁾
(millions)
Subsidiary debt⁽²⁾	$	126	$	126
Commodity transactions⁽³⁾		3,001		375
Lease obligation for power generation facility⁽⁴⁾		757		757
Nuclear obligations⁽⁵⁾		231		52
Other		498		126
Total	$	4,613	$	1,436

(1)

Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2010 based upon prevailing economic conditions and fact patterns specific to each guarantee arrangement. For those guarantees related to obligations that are recorded as liabilities by Dominion’s subsidiaries, the value includes the recorded amount.

(2)

Guarantees of debt of certain DEI subsidiaries. In the event of default by the subsidiaries, Dominion would be obligated to repay such amounts.

(3)

Guarantees related to energy trading and marketing activities and other commodity commitments of certain subsidiaries, including subsidiaries of Virginia Power and DEI. These guarantees were provided to counterparties in order to facilitate physical and financial transactions in gas, oil, electricity, pipeline capacity, transportation and related commodities and services. If any of these subsidiaries fail to perform or pay under the contracts and the counterparties seek performance or payment, Dominion would be obligated to satisfy such obligation. Dominion and its subsidiaries receive similar guarantees as collateral for credit extended to others. The value provided includes certain guarantees that do not have stated limits.

(4)

Guarantee of a DEI subsidiary’s leasing obligation for Fairless.

(5)

Guarantees related to certain DEI subsidiaries’ potential retrospective premiums that could be assessed if there is a nuclear incident under Dominion’s nuclear insurance programs and guarantees for a DEI subsidiary’s and Virginia Power’s commitment to buy nuclear fuel. Excludes Dominion’s agreement to provide up to $150 million and $60 million to two DEI subsidiaries to pay the operating expenses of Millstone and Kewaunee, respectively, in the event of a prolonged outage, as part of satisfying certain NRC requirements concerned with ensuring adequate funding for the operations of nuclear power stations.

Additionally, as of December 31, 2010 Dominion had purchased $87 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $136 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Dominion is obligated to indemnify the respective surety bond company for any amounts paid.

VIRGINIA POWER

As of December 31, 2010, Virginia Power had issued $16 million of guarantees primarily to support tax-exempt debt issued through conduits. Virginia Power had also purchased $39 million of surety bonds for various purposes, including providing workers’ compensation coverage, and authorized the issuance of standby letters of credit by financial institutions of $91 million to facilitate commercial transactions by its subsidiaries with third parties. Under the terms of surety bonds, Virginia Power is obligated to indemnify the respective surety bond company for any amounts paid.

Indemnifications

As part of commercial contract negotiations in the normal course of business, Dominion and Virginia Power may sometimes agree

to make payments to compensate or indemnify other parties for possible future unfavorable financial consequences resulting from specified events. The specified events may involve an adverse judgment in a lawsuit or the imposition of additional taxes due to a change in tax law or interpretation of the tax law. Dominion and Virginia Power are unable to develop an estimate of the maximum potential amount of future payments under these contracts because events that would obligate them have not yet occurred or, if any such event has occurred, they have not been notified of its occurrence. However, at December 31, 2010, Dominion and Virginia Power believe future payments, if any, that could ultimately become payable under these contract provisions, would not have a material impact on their results of operations, cash flows or financial position.

Workforce Reduction Program

In the first quarter of 2010, Dominion and Virginia Power announced a workforce reduction program that reduced their total workforces by approximately 9% and 11%, respectively, during 2010. The goal of the workforce reduction program was to reduce operations and maintenance expense growth and further improve the efficiency of the Companies. In the first quarter of 2010, Dominion recorded a $338 million ($206 million after-tax) charge, including $202 million ($123 million after-tax) at Virginia Power, primarily reflected in other operations and maintenance expense in their Consolidated Statements of Income due to severance pay and other benefits related to the workforce reduction program. During 2010, Dominion and Virginia Power paid $109 million and $104 million, respectively, of costs related to the program. The terms of the workforce reduction program were consistent with the Companies’ existing severance plan.

NOTE 24. CREDIT RISK

Credit risk is the risk of financial loss if counterparties fail to perform their contractual obligations. In order to minimize overall credit risk, credit policies are maintained, including the evaluation of counterparty financial condition, collateral requirements and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, counterparties may make available collateral, including letters of credit or cash held as margin deposits, as a result of exceeding agreed-upon credit limits, or may be required to prepay the transaction.

Dominion and Virginia Power maintain a provision for credit losses based on factors surrounding the credit risk of their customers, historical trends and other information. Management believes, based on credit policies and the December 31, 2010 provision for credit losses, that it is unlikely that a material adverse effect on financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

GENERAL

DOMINION

As a diversified energy company, Dominion transacts primarily with major companies in the energy industry and with commercial and residential energy consumers. These transactions principally occur in the Northeast, mid-Atlantic and Midwest regions of the U.S. and Texas. Dominion does not believe that this geo-

graphic concentration contributes significantly to its overall exposure to credit risk. In addition, as a result of its large and diverse customer base, Dominion is not exposed to a significant concentration of credit risk for receivables arising from electric and gas utility operations.

Dominion’s exposure to credit risk is concentrated primarily within its energy marketing and price risk management activities, as Dominion transacts with a smaller, less diverse group of counterparties and transactions may involve large notional volumes and potentially volatile commodity prices. Energy marketing and price risk management activities include trading of energy-related commodities, marketing of merchant generation output, structured transactions and the use of financial contracts for enterprise-wide hedging purposes. Gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2010, Dominion’s gross credit exposure totaled $620 million. After the application of collateral, credit exposure is reduced to $591 million. Of this amount, investment grade counterparties, including those internally rated, represented 85%. One counterparty exposure represents 10% of Dominion’s total exposure and is a large financial institution rated investment grade.

VIRGINIA POWER

Virginia Power sells electricity and provides distribution and transmission services to customers in Virginia and northeastern North Carolina. Management believes that this geographic concentration risk is mitigated by the diversity of Virginia Power’s customer base, which includes residential, commercial and industrial customers, as well as rural electric cooperatives and municipalities. Credit risk associated with trade accounts receivable from energy consumers is limited due to the large number of customers. Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Virginia Power’s gross credit exposure for each counterparty is calculated as outstanding receivables plus any unrealized on- or off-balance sheet exposure, taking into account contractual netting rights. Gross credit exposure is calculated prior to the application of collateral. At December 31, 2010, Virginia Power’s exposure to potential concentrations of credit risk was not considered material.

CREDIT-RELATED CONTINGENT PROVISIONS

The majority of Dominion’s derivative instruments contain credit-related contingent provisions. These provisions require Dominion to provide collateral upon the occurrence of specific events, primarily a credit downgrade. If the credit-related contingent features underlying these instruments that are in a liability position and not fully collateralized with cash were fully triggered as of December 31, 2010 and 2009, Dominion would have been required to post an additional $88 million and $36 million, respectively, of collateral to its counterparties. The collateral that would be required to be posted includes the impacts of any offsetting asset positions and any amounts already posted for derivatives, non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. Dominion had posted $54 million in collateral, including $19 million of letters of credit at December 31, 2010 and $62

million in collateral, including $48 million of letters of credit at December 31, 2009, related to derivatives with credit-related contingent provisions that are in a liability position and not fully collateralized with cash. The collateral posted includes any amounts paid related to non-derivative contracts and derivatives elected under the normal purchases and normal sales exception, per contractual terms. The aggregate fair value of all derivative instruments with credit-related contingent provisions that are in a liability position and not fully collateralized with cash as of December 31, 2010 and 2009 was $210 million and $181 million, respectively, which does not include the impact of any offsetting asset positions. See Note 8 for further information about derivative instruments.

NOTE 25. DOMINION CAPITAL, INC.

At December 31, 2007, DCI held an investment in the subordinated notes of a third-party CDO entity. The CDO entity’s primary focus is the purchase and origination of middle market senior secured first and second lien commercial and industrial loans in both the primary and secondary loan markets. Dominion concluded previously that the CDO entity was a VIE and that DCI was the primary beneficiary of the CDO entity and therefore Dominion consolidated the CDO entity at December 31, 2007.

In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes to a third party, effectively eliminating the variability of its interest, and therefore deconsolidated the CDO entity as of March 31, 2008 and recognized impairment losses of $62 million ($38 million after-tax), which were recorded in other operations and maintenance expense in its Consolidated Statement of Income. In connection with the sale of the subordinated notes, in April 2008, Dominion received proceeds of $54 million, including accrued interest. This sale concluded Dominion’s efforts to divest of DCI, since its remaining assets are aligned with Dominion’s core business.

NOTE 26. RELATED-PARTY TRANSACTIONS

Virginia Power engages in related-party transactions primarily with other Dominion subsidiaries (affiliates). Virginia Power’s receivable and payable balances with affiliates are settled based on contractual terms or on a monthly basis, depending on the nature of the underlying transactions. Virginia Power is included in Dominion’s consolidated federal income tax return and participates in certain Dominion benefit plans. A discussion of significant related party transactions follows.

Transactions with Affiliates

Virginia Power transacts with affiliates for certain quantities of natural gas and other commodities in the ordinary course of business. Virginia Power also enters into certain commodity derivative contracts with affiliates. Virginia Power uses these contracts, which are principally comprised of commodity swaps and options, to manage commodity price risks associated with purchases of natural gas.

DRS provides accounting, legal, finance and certain administrative and technical services to Virginia Power. Presented below are significant transactions with DRS and other affiliates:


Year Ended December 31,	2010		2009		2008
(millions)
Commodity purchases from affiliates	$	373	$	327	$	527
Services provided by affiliates		469		420		399

During 2009, Virginia Power purchased turbines from an affiliate for $58 million to be used in the Bear Garden power station, currently under construction.

The following table presents Virginia Power’s borrowings from Dominion under short-term arrangements:


At December 31,	2010		2009
(millions)
Outstanding borrowings, net of repayments, under the Dominion money pool for Virginia Power’s nonregulated subsidiaries	$	24	$	2
Short-term demand note borrowings from Dominion		79		—

Virginia Power incurred interest charges related to its borrowings from Dominion of $1 million, $5 million, and $10 million in 2010, 2009 and 2008, respectively.

In 2010, 2009 and 2008, Virginia Power issued 33,013, 31,877 and 11,786 shares of its common stock to Dominion as settlement of approximately $1 billion, $1 billion and $350 million of short-term demand note borrowings from Dominion, respectively.

NOTE 27. OPERATING SEGMENTS

Dominion and Virginia Power are organized primarily on the basis of products and services sold in the U.S. A description of the operations included in the Companies’ primary operating segments is as follows:


Primary Operating Segment	Description of Operations	Dominion	Virginia Power
DVP	Regulated electric distribution	X		X
	Regulated electric transmission	X		X
	Nonregulated retail energy marketing (electric and gas)	X
Dominion Generation	Regulated electric fleet	X		X
	Merchant electric fleet	X
Dominion Energy	Gas transmission and storage	X
	Gas distribution and storage	X
	LNG import and storage	X
	Producer services	X

In addition to the operating segments above, the Companies also report a Corporate and Other segment.

The Corporate and Other Segment of Virginia Power 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.

The Corporate and Other Segment of Dominion includes its corporate, service company and other functions (including unallocated debt) and the net impact of Peoples and certain DCI operations, which are discussed in Notes 4 and 25, respectively. 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.

DOMINION

In 2010, Dominion reported after-tax net benefits of $837 million for specific items in the Corporate and Other segment, with $1 billion of these net benefits attributable to its operating segments.

The net benefits for specific items in 2010 primarily related to the impact of the following items:

A $2.5 billion ($1.4 billion after-tax) benefit resulting from the gain on the sale of substantially all of Dominion’s Appalachian E&P operations net of charges related to the divestiture, attributable to Dominion Energy; partially offset by

A $338 million ($206 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

DVP ($67 million after-tax);

Dominion Energy ($24 million after-tax); and

Dominion Generation ($115 million after-tax);

A $134 million ($155 million after-tax) loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale, attributable to the Corporate and Other segment; and

A $194 million ($127 million after-tax) impairment charge at certain merchant generation power stations, attributable to Dominion Generation.

In 2009, Dominion reported after-tax net expenses of $655 million for specific items in the Corporate and Other segment, with $688 million of these net expenses attributable to its operating segments.

The net expenses for specific items in 2009 primarily related to the impact of the following items:

A $455 million ($281 million after-tax) ceiling test impairment charge related to the carrying value of Dominion’s E&P properties, attributable to Dominion Energy; and

A $712 million ($435 million after-tax) charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings, attributable to:

Dominion Generation ($257 million after-tax); and

DVP ($178 million after-tax).

In 2008, Dominion reported after-tax net expenses of $3 million for specific items in the Corporate and Other segment, with $134 million of these net expenses attributable to its operating segments.

The net expenses for specific items in 2008 primarily related to the impact of the following items:

$180 million ($109 million after-tax) of impairment charges reflecting other-than-temporary declines in the fair value of securities held as investments in nuclear decommissioning trusts as of December 31, 2008, attributable to Dominion Generation;

A $62 million ($38 million after-tax) impairment charge related to the disposition of certain DCI investments. attributable to the Corporate and Other segment;

A $42 million ($26 million after-tax) charge related to post-closing adjustments to the gain on the sale of the non-Appalachian E&P business, attributable to the Corporate and Other segment;

$39 million ($24 million after-tax) of impairment charges related to non-refundable deposits for certain generation-related vendor contracts, attributable to Dominion Generation; and

A $119 million ($192 million after-tax) benefit reflecting the discontinued operations of Peoples, attributable to the Corporate and Other segment.

The following table presents segment information pertaining to Dominion’s operations:

At December 31, 2010, 2009, and 2008, none of Dominion’s long-lived assets and no significant percentage of its operating revenues were associated with international operations.

VIRGINIA POWER

The majority of Virginia Power’s revenue is provided through tariff rates. Generally, such revenue is allocated for management reporting based on an unbundled rate methodology among Virginia Power’s DVP and Dominion Generation segments.

In 2010, Virginia Power reported after-tax net expenses of $153 million for specific items attributable to its operating segments in the Corporate and Other segment.

The net expenses for specific items in 2010 primarily related to the impact of the following:

A $202 million ($123 million after-tax) charge primarily reflecting severance pay and other benefits related to a workforce reduction program, attributable to:

DVP ($63 million after-tax); and

Dominion Generation ($60 million after-tax).

The following table presents segment information pertaining to Virginia Power’s operations:

NOTE 28. QUARTERLY FINANCIAL AND COMMON STOCK DATA (UNAUDITED)

A summary of Dominion’s and Virginia Power’s quarterly results of operations for the years ended December 31, 2010 and 2009 follows. Amounts reflect all adjustments necessary in the opinion of management for a fair statement of the results for the interim periods. Results for interim periods may fluctuate as a result of weather conditions, changes in rates and other factors.

DOMINION

First
Quarter

Second
Quarter

Third
Quarter

Fourth
Quarter

Full Year

(millions, except
per share
amounts)

2010

Operating revenue

4,168

3,333

3,950

3,746

15,197

Income from operations

734

3,110

1,119

737

5,700

Income from continuing operations⁽¹⁾

323

1,759

575

306

2,963

Income (loss) from discontinued operations⁽¹⁾

(149

)

—

)

(155

)

Net income including noncontrolling interests

178

1,765

579

303

2,825

Net income attributable to Dominion

174

1,761

575

298

2,808

Basic EPS:

Income from continuing operations⁽¹⁾

0.54

2.98

0.98

0.53

5.03

Income (loss) from discontinued operations⁽¹⁾

(0.25

)

—

(0.01

)

(0.26

)

Net income attributable to Dominion

0.29

2.98

0.98

0.52

4.77

Diluted EPS:

Income from continuing operations⁽¹⁾

0.54

2.98

0.98

0.52

5.02

Income (loss) from discontinued operations⁽¹⁾

(0.25

)

—

(0.01

)

(0.26

)

Net income attributable to Dominion

0.29

2.98

0.98

0.51

4.76

Dividends paid per share

0.4575

1.83

Common stock prices (intraday high-low)

41.61 -
36.12

42.56 -
38.05

44.94
38.59

45.12 -
41.13

45.12 -
36.12


	First Quarter		Second Quarter			Third Quarter			Fourth Quarter			Full Year
(millions, except per share amounts)
2009
Operating revenue	$	4,586	$	3,406		$	3,630		$	3,176		$	14,798
Income from operations		664		889			1,088			(72	)		2,569
Income from continuing operations⁽¹⁾		239		469			635			(82	)		1,261
Income (loss) from discontinued operations⁽¹⁾		9		(15	)		(41	)		73			26
Net income including noncontrolling interests		252		458			598			(4	)		1,304
Net income attributable to Dominion		248		454			594			(9	)		1,287
Basic and Diluted EPS:
Income from continuing operations⁽¹⁾		0.41		0.79			1.07			(0.13	)		2.13
Income (loss) from discontinued operations⁽¹⁾		0.01		(0.03	)		(0.07	)		0.12			0.04
Net income attributable to Dominion		0.42		0.76			1.00			(0.01	)		2.17
Dividends paid per share		0.4375		0.4375			0.4375			0.4375			1.75
Common stock prices (intraday high-low)	$	37.18 - 27.15	$	33.93 - 28.70		$	34.84 - 32.10		$	39.79 - 33.15		$	39.79 - 27.15

(1)

Amounts attributable to Dominion’s common shareholders.

Dominion’s 2010 results include the impact of the following significant items:

First quarter results include a $206 million after-tax charge primarily reflecting severance pay and other benefits related to a workforce reduction program and a $149 million after-tax loss from the discontinued operations of Peoples primarily reflecting a net loss on the sale.

Second quarter results include a $1.4 billion after-tax benefit resulting from the gain on the sale of substantially all of Dominion’s Appalachian E&P operations net of charges related to the divestiture and a $95 million after-tax impairment charge at State Line to reflect the estimated fair value of the power station.

Dominion’s 2009 results include the impact of the following significant items:

First quarter results include a $272 million after-tax ceiling impairment charge related to the carrying value of its E&P properties and a $50 million after-tax net loss on investments held in nuclear decommissioning trust funds.

Second quarter results include a $62 million after-tax reduction in other operations and maintenance expense due to a downward revision in the nuclear decommissioning ARO for a power station unit that is no longer in service.

Third quarter results include a $34 million after-tax net gain on investments held in nuclear decommissioning trust funds.

Fourth quarter results include a $435 million after-tax charge in connection with the settlement of Virginia Power’s 2009 base rate case proceedings.

VIRGINIA POWER

Virginia Power’s quarterly results of operations were as follows:


	First Quarter		Second Quarter		Third Quarter		Fourth Quarter			Year
(millions)
2010
Operating revenue	$	1,739	$	1,711	$	2,111	$	1,658		$	7,219
Income from operations		254		479		673		235			1,641
Net income		95		267		380		110			852
Balance available for common stock		91		263		376		105			835
2009
Operating revenue	$	1,859	$	1,675	$	1,938	$	1,112		$	6,584
Income (loss) from operations		402		299		554		(507	)		748
Net income (loss)		204		149		315		(312	)		356
Balance available for common stock		200		145		311		(317	)		339

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

DOMINION

Senior management, including Dominion’s CEO and CFO, evaluated the effectiveness of Dominion’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Dominion’s CEO and CFO have concluded that Dominion’s disclosure controls and procedures are effective. There were no changes in Dominion’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Dominion’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for Dominion’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as Dominion does throughout all aspects of its business.

Dominion maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2010 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for the report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2010, Dominion makes the following assertion:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Management evaluated Dominion’s internal control over financial reporting as of December 31, 2010. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2010.

Dominion’s independent registered public accounting firm is engaged to express an opinion on Dominion’s internal control over financial reporting, as stated in their report which is included herein.

February 25, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Dominion Resources, Inc.

Richmond, Virginia

We have audited the internal control over financial reporting of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2010, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Dominion’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on Dominion’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes

in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Dominion maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2010 of Dominion and our report dated February 25, 2011, expressed an unqualified opinion on those financial statements.

/s/ Deloitte & Touche LLP

Richmond, Virginia

February 25, 2011

VIRGINIA POWER

Senior management, including Virginia Power’s CEO and CFO, evaluated the effectiveness of Virginia Power’s disclosure controls and procedures as of the end of the period covered by this report. Based on this evaluation process, Virginia Power’s CEO and CFO have concluded that Virginia Power’s disclosure controls and procedures are effective. There were no changes in Virginia Power’s internal control over financial reporting that occurred during the last fiscal quarter that have materially affected, or are reasonably likely to materially affect, Virginia Power’s internal control over financial reporting.

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of Virginia Electric and Power Company (Virginia Power) understands and accepts responsibility for Virginia Power’s financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Virginia Power continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Virginia Power maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that its assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Board of Directors also serves as Virginia Power’s Audit Committee and meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss Virginia Power’s auditing, internal accounting control and financial reporting matters and to ensure that each is properly discharging its responsibilities.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act require Virginia Power’s 2010 Annual Report to contain a management’s report regarding the effectiveness of internal control. As a basis for the report, Virginia Power tested and evaluated the design and operating effectiveness of internal controls. Based on the assessment as of December 31, 2010, Virginia Power makes the following assertion:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.

Management evaluated Virginia Power’s internal control over financial reporting as of December 31, 2010. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, Management believes that Virginia Power maintained effective internal control over financial reporting as of December 31, 2010.

This annual report does not include an attestation report of Virginia Power’s registered public accounting firm regarding internal control over financial reporting. Management’s report is not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to a permanent exemption under the Dodd-Frank Act.

February 25, 2011

The following information for Dominion is incorporated by reference from the 2011 Proxy Statement, File No. 001-08489, which will be filed on or around March 31, 2011 (the 2011 Proxy Statement):

The information concerning the executive officers of Dominion required by this item is included in Part I of this Form 10-K under the caption Executive Officers of Dominion. Each executive officer of Dominion is elected annually.

Information concerning directors of Virginia Power, each of whom is elected annually, is as follows:

Information concerning the executive officers of Virginia Power, each of whom is elected annually is as follows:

To Virginia Power’s knowledge, for the fiscal year ended December 31, 2010, all Section 16(a) filing requirements applicable to its executive officers and directors were satisfied.

Virginia Power is a wholly-owned subsidiary of Dominion. As permitted by SEC rules, its Board of Directors serves as Virginia Power’s Audit Committee and is comprised entirely of executive officers of Virginia Power or Dominion. Virginia Power’s Board of Directors has determined that Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers are “audit committee financial experts” as defined by the SEC. As executive officers of Virginia Power and/or Dominion, Thomas F. Farrell II, Mark F. McGettrick and Steven A. Rogers are not deemed independent.

Virginia Power has adopted a Code of Ethics that applies to its principal executive, financial and accounting officers, as well as its employees. This Code of Ethics is the same as Dominion adopted and is available on the corporate governance section of Dominion’s website (www.dom.com). You may also request a copy of the Code of Ethics, free of charge, by writing or telephoning to: Corporate Secretary, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Any waivers or changes to Virginia Power’s Code of Ethics will be posted on the Dominion website.

matters. Virginia Power’s Board approves all compensation paid to executive officers based on the CGN Committee’s recommendations. None of Virginia Power’s directors receive any compensation for services they provide as directors.

Because the CGN Committee effectively administers one compensation program for all of Dominion, the following discussion and analysis is based on Dominion’s overall compensation program.

INTRODUCTION

This CD&A provides a detailed explanation of the objectives and principles that underlie Dominion’s executive compensation program, its elements and the way performance is measured, evaluated and rewarded. It also describes Dominion’s compensation decision-making process. Dominion’s executive compensation program is designed to pay for performance and played an important role in the company’s success in 2010 by linking a significant amount of compensation to the achievement of performance goals.

The program and processes generally apply to all officers, but this discussion and analysis focuses primarily on compensation for the NEOs of Virginia Power. During 2010, Virginia Power’s NEOs were:

Thomas F. Farrell II, Chairman, President and CEO

Mark F. McGettrick, Executive Vice President and CFO

Paul D. Koonce, President and COO—DVP

David A. Christian, President and COO—Generation

James F. Stutts, Senior Vice President and General Counsel (retired January 1, 2011)

The CGN Committee determines the compensation payable to officers of Dominion and its wholly-owned subsidiaries on an aggregate basis, taking into account all services performed by the officers, whether for Dominion or one or more of its subsidiaries. For the NEOs included in Dominion’s annual proxy statement, these aggregate amounts are reported in the Summary Compensation Table and related executive compensation tables. For purposes of reporting each NEO’s compensation from Virginia Power in the Summary Compensation Table (and related tables that follow) in this Item 11, the aggregate compensation for each NEO is pro-rated based on the ratio of services performed by the NEO for Virginia Power to the NEO’s total services performed for all of Dominion. For officers who are NEOs of both Virginia Power and Dominion, the amounts reported in the tables below are part of, and not in addition to the aggregate compensation amounts that are reported for these NEOs in Dominion’s 2011 Proxy Statement. The CD&A below discusses the CGN Committee’s decisions with respect to each NEO’s aggregate compensation for all services performed for all of Dominion, not just the pro-rata portion attributable to the NEO’s services for Virginia Power.

OBJECTIVES OF DOMINION’S EXECUTIVE COMPENSATION PROGRAM AND THE COMPENSATION DECISION-MAKING PROCESS

Objectives

The major objectives of Dominion’s compensation program are to:

Attract, develop and retain an experienced and highly qualified management team;

Motivate and reward superior performance that supports the business and strategic plans and contributes to the long-term success of the company;

Align the interests of management with those of Dominion’s shareholders by placing a substantial portion of pay at risk through performance goals that, if achieved, are expected to increase total shareholder return;

Promote internal pay equity; and

Reinforce Dominion’s core values of safety, ethics, excellence and “One Dominion” – Dominion’s term for teamwork.

These objectives provide the framework for the compensation decisions. To determine if Dominion is meeting the objectives of its compensation program, the CGN Committee reviews and compares Dominion’s actual performance to its short-term and long-term goals, strategies, and peer companies’ performance.

Dominion’s 2010 performance indicates that the design of Dominion’s compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 12 to 34 years. Dominion has attracted, motivated and maintained a superior leadership team with skills, industry knowledge and institutional experience that strengthen their ability to act as sound stewards of Dominion’s shareholder dollars. Dominion is performing well relative to its internal goals and as compared to its peers.

The Process for Setting Compensation

The CGN Committee is responsible for reviewing and approving NEO compensation and the overall executive compensation program. Each year, the CGN Committee reviews and considers a comprehensive assessment and analysis of the executive compensation program, including the elements of each NEO’s compensation, with input from management and the independent compensation consultant. As part of its assessment, the CGN Committee reviews the performance of the CEO and other executive officers, meets at least annually with the CEO to discuss succession planning for his position and the positions of the company’s senior officers, reviews the share ownership guidelines and executive officer compliance with the guidelines, and establishes compensation programs designed to achieve Dominion’s objectives.

THE ROLE OF THE INDEPENDENT COMPENSATION CONSULTANT

The CGN Committee’s practice has been to retain an independent compensation consultant, PM&P, to advise the committee on executive and director compensation matters. PM&P does not provide any services to Dominion other than its consulting services to the CGN Committee related to executive and director compensation. The PM&P consultant participates in meetings with the CGN Committee, either in person or by teleconference, and communicates directly with the chairman of the committee outside of the committee meetings as requested by the chairman of the committee. PM&P also reviewed meeting materials for the CGN Committee and provided the following services related to the 2010 executive compensation program:

Provided independent advice to the CGN Committee regarding the appropriateness of Dominion’s peer group;

Participated in CGN Committee executive sessions without management present to discuss CEO compensation and any other relevant matters, including the appropriate relationship between pay and performance and emerging trends, to answer technical questions, and to review and comment on management proposals and analyses of peer group compensation data; and

Generally reviewed and offered advice as requested by or on behalf of the CGN Committee regarding other aspects of the executive compensation program, including special awards, best practices and other matters.

MANAGEMENT’S ROLE IN DOMINION’S PROCESS

Although the CGN Committee has the responsibility to approve and monitor all compensation for the NEOs, management plays an important role in determining executive compensation. Under the direction of the Corporate Secretary, internal compensation specialists provide the CGN Committee with data, analysis and counsel regarding the executive compensation program, including an ongoing assessment of the effectiveness of the program, peer practices, and executive compensation trends and best practices. The CEO, CFO and Corporate Secretary, along with the internal compensation and financial specialists, assist in the design of the incentive compensation plans, including performance target recommendations consistent with the strategic goals of the company, and in establishing the peer group. Management also works with the Chairman of the CGN Committee to establish the agenda and prepare meeting information for each committee meeting.

On an annual basis, the CEO is responsible for reviewing with the CGN Committee Dominion’s succession plans for his own position and for Dominion’s senior officers. He is also responsible for reviewing the performance of his senior officers, including the other NEOs, with the CGN Committee at least annually. He makes recommendations on the compensation and benefits for the NEOs (other than himself) to the CGN Committee and provides other information and counsel as appropriate or as requested by the CGN Committee, but all decisions are ultimately made by the CGN Committee.

THE PEER GROUP AND PEER GROUP COMPARISONS

Each year, the CGN Committee approves a peer group of companies. In selecting the peer group, Dominion uses a methodology recommended by PM&P to identify companies in the industry

that compete for customers, executive talent and investment capital. Dominion screens this group based on size and usually eliminates companies that are much smaller or larger than Dominion’s size in revenues, assets and market capitalization. Dominion also considers the geographic locations and the regulatory environment in which potential peer companies operate.

Dominion’s peer group is generally consistent from year to year, with merger and acquisition activity being the primary reason for any changes. The 2010 peer group was the same as the 2009 peer group and consisted of the following 14 energy companies:

Ameren Corporation

American Electric Power Company, Inc.

Constellation Energy Group, Inc.

DTE Energy Company

Duke Energy Corporation

Entergy Corporation

Exelon Corporation

FirstEnergy Corp.

NextEra Energy, Inc. (formerly FPL Group, Inc.)

NiSource, Inc.

PPL Corporation

Progress Energy, Inc.

Public Service Enterprise Group Inc.

Southern Company

The CGN Committee, PM&P and management use peer company data to: (i) compare Dominion’s stock and financial performance against its peers using a number of different metrics and time periods to evaluate how Dominion is performing as compared to its peers; (ii) analyze compensation practices within the industry; (iii) evaluate peer company practices and determine peer median and 75th percentile ranges for base pay, annual incentive pay, long-term incentive pay, total direct compensation generally and for specific positions; and (iv) compare Employment Continuity Agreements and other benefits. In setting the levels for base pay, annual incentive pay, long-term incentive pay and total direct compensation, the CGN Committee also takes into consideration Dominion’s larger size compared with the median of the peer group.

SURVEY DATA

During 2009 and 2010, survey compensation data was used only to provide a general understanding of compensation practices and trends. Dominion did not benchmark or otherwise use broad-based market data as the basis for 2009 or 2010 compensation decisions for the NEOs and other senior officers. Going forward, the CGN Committee intends to continue its practice of emphasizing individual and company specific considerations, including internal pay equity, along with peer company data in establishing compensation opportunities. The CGN Committee believes that this emphasis better reflects Dominion’s specific needs in its distinct competitive market and with respect to its size and complexity versus its peers.

COMPENSATION DESIGN AND RISK

Management, including Dominion’s chief risk officer and other executives, annually reviews the overall structure of Dominion’s executive compensation program and policies to ensure they are consistent with effective management of enterprise key risks and that they do not encourage executives to take unnecessary or excessive risks that could threaten the value of the enterprise. With respect to the programs and policies that apply to the NEOs, this review includes:

Analysis of how different elements of the compensation programs may increase or mitigate risk-taking;

Analysis of performance metrics used for short-term and long-term incentive programs and the relation of such incentives to the objectives of Dominion;

Analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate; and

Analysis of the overall structure of compensation programs as related to business risks.

Among the factors considered in management’s assessment are: the balance of the overall program design, including the mix of cash and equity compensation; the mix of fixed and variable compensation; the balance of short-term and long-term objectives of incentive compensation; the performance metrics, performance targets, threshold performance requirements and capped payouts related to incentive compensation; the clawback provision on incentive compensation; Dominion’s share ownership guidelines, including share ownership levels and retention practices; prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock; and internal controls and oversight structures in place.

Management reviewed and discussed the results of this assessment with the CGN Committee. Based on this review, the CGN Committee believes Dominion’s well-balanced mix of salary and short-term and long-term incentives, as well as the performance

metrics that are included in the incentive programs, are appropriate and consistent with Dominion’s risk management practices and overall strategies.

OTHER TOOLS

The CGN Committee uses a number of tools in its annual review of the compensation of the CEO and other NEOs, including charts illustrating the total range of payouts for each performance-based compensation element under a number of different scenarios; spreadsheets showing the cumulative dollar impact on total direct compensation that could result from implementing proposals on any single element of compensation; graphs showing the relationship between the CEO’s pay and that of the next highest-paid officer and NEOs as a group; and other information the CGN Committee may request in its discretion. Management’s internal compensation specialists provide the CGN Committee with detailed comparisons of the design and features of Dominion’s long-term incentive and other executive benefit programs with available information regarding similar programs at the peer companies. These tools are used as part of the overall process to ensure that the program results in appropriate pay relationships as compared to Dominion’s peer companies and internally among the NEOs, and that an appropriate balance of at-risk, performance-based compensation is maintained to support the program’s core objectives.

Internal pay equity considerations, such as the relative importance of a particular position or individual officer to Dominion’s strategy and success, and comparability to other officer positions at Dominion;

Retention and market competitive concerns; and

The officer’s role in any succession plan for other key positions.

The CGN Committee evaluates each NEO’s base salary, total cash and total direct compensation opportunities against peer group data, both at peer group median and the 75th percentile, to ensure the compensation levels are appropriately competitive, but except for base salary, does not target these compensation levels at a particular percentile or range of the peer group data. Base salary is generally targeted at or slightly above the peer group 50th percentile (median). Compensation decisions are based on what the CGN Committee deems appropriate, taking into consideration a number of factors, including those discussed above. However, actual compensation targets may range from below peer median to at or above the 75th percentile based on a number of factors including experience, tenure and internal pay equity considerations. As part of this analysis, the CGN Committee also takes into account Dominion’s larger size and complexity compared to its peer companies.

In setting compensation for 2010, due to volatile market conditions and budget considerations, base salaries were generally maintained at the 2009 levels for all officers, including all NEOs, and adjustments were made to performance-based compensation target levels for certain officers. Based on the review of peer company compensation data, each NEO’s job performance, and internal pay equity considerations such as scope and complexity of the position relative to other positions at the company, the CGN Committee determined it was appropriate to increase the target levels under the annual incentive plan for Messrs. McGettrick and Christian and for all of the NEOs under the long-term incentive program, as described below in Base Salary, Annual Incentive Plan and Long-Term Incentive Program.

CEO Compensation Relative to Other NEOs

Mr. Farrell participates in the same compensation programs and receives compensation based on the same philosophy and factors as other NEOs. Application of the same philosophy and factors to Mr. Farrell’s position results in overall CEO compensation that is significantly higher than the compensation of the other NEOs. His compensation is commensurate with his greater responsibilities and decision-making authority, broader scope of duties that encompasses the entirety of the company (as compared to the other NEOs who are responsible for significant but distinct areas within the company) and his overall responsibility for corporate strategy. His compensation also reflects his role as the primary corporate representative to investors, customers, regulators, analysts, legislators, industry and the media.

Dominion considers CEO compensation trends as compared to the next highest-paid officer as well as to other executive officers as a group, over a multi-year period to monitor the ratio of Mr. Farrell’s pay relative to the pay of other executive officers based on (i) salary only and (ii) total direct compensation. Dominion also compares its ratios to that of its peers to confirm that its ratios are consistent with practices at the peer companies. There is no particular targeted ratio or goal, but instead the CGN

Committee considers year-to-year trends and comparisons with peer companies. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review in 2010.

Allocation of Total Direct Compensation in 2010

Consistent with Dominion’s objective to reward strong performance based on the achievement of short-term and long-term goals, a significant portion of total cash and total direct compensation is at risk. Approximately 88% of Mr. Farrell’s targeted 2010 total direct compensation is performance-based, tied to pre-approved performance metrics or tied to the performance of Dominion’s stock. For the other NEOs, performance-based and stock-based compensation ranges from 71% to 79% of targeted 2010 total direct compensation. This compares to an average of approximately 53% of targeted compensation at risk for most officers at the vice president level and an average of approximately 12% of total pay at risk for non-officer employees.

The charts below illustrate the elements of total direct compensation opportunities in 2010 for Mr. Farrell and the other NEOs as a group and the allocation of such compensation among base salary, targeted 2010 annual incentive plan award and targeted 2010 long-term incentive compensation.

Chart does not include the restricted stock grant made to Mr. Farrell for strategic and retention purposes in December 2010, as discussed under Other Restricted Stock Grant.

Base Salary

Base salary compensates officers, along with the rest of the work force, for committing significant time to working on Dominion’s behalf. Annual salary reviews achieve two primary purposes: (i) an annual adjustment, as appropriate, to keep salaries in line and

competitive with the peer group and to reflect changes in responsibility, including promotions; and (ii) a motivational tool to acknowledge and reward excellent individual performance, special skills, experience, the strategic impact of a position relative to other executives and other relevant considerations.

The primary goal is to compensate its officers at a level that best achieves its objectives and reflects the considerations discussed above. Dominion believes that an overall goal of targeting base salary at or slightly above the peer group median is a conservative but appropriate target for base pay. However, an individual’s compensation may be below or above Dominion’s target range based on a number of factors such as performance, tenure, and other factors explained above in Factors in Setting Compensation. In addition to being ranked above the peer group median in 2010 in terms of revenues, assets and market capitalization, the scope of Dominion’s business operations is complex and unique in its industry. Successfully managing such a broad and complex business requires a skilled and experienced management team. Dominion believes it would not be able to successfully recruit and retain such a team if the base pay for officers was generally below the peer group median.

Although individual and company performance would have supported merit increases for 2010 for the NEOs, due to uncertain market conditions and the current economic climate, the CGN Committee froze base salaries for most officers, including all NEOs at their 2009 levels.

In September 2010, the CGN Committee considered Dominion’s exceptional performance year-to-date and determined it was appropriate to authorize a one-time, 2% merit lump sum payment to all employees (other than those whose compensation is determined pursuant to the terms of a collective bargaining agreement). This 2% merit lump sum payment was also paid to all NEOs. The 2% merit lump sum payment was within the range of general market increases for 2010 merit awards, based on Dominion’s understanding of compensation practices and trends. As a special one-time lump sum payment, however, the payment did not increase base salaries or change compensation levels used in calculating retirement plan and other employee benefits.

Annual Incentive Plan

OVERVIEW

The AIP plays an important role in meeting Dominion’s overall objective of rewarding strong performance. The AIP is a cash-based program focused on short-term goal accomplishments and is designed to:

Tie interests of Dominion’s shareholders and employees closely together;

Focus the workforce on company, operating group, team and individual goals that ultimately influence operational and financial results;

Reward corporate and operating unit earnings performance;

Reward safety and other operating and stewardship goal success;

Emphasize teamwork by focusing on common goals;

Appropriately balance risk and reward; and

Provide a competitive total compensation opportunity.

TARGET AWARDS

An NEO’s compensation opportunity under the AIP is based on a target award. Target awards are determined as a percentage of a

participant’s base salary (for example, 95% of base salary). The target award is the amount of cash that will be paid if a participant achieves a score of 100% for the goals established at the beginning of the year and the plan is funded at the full funding target set for the year. Participants who retire during the plan year are eligible to receive a pro-rated payment of their AIP award after the end of the plan year based on final funding and goal achievement. Participants who terminate employment during the plan year and who are not eligible to retire (before attainment of age 55) forfeit their AIP award.

AIP target award levels are established based on a number of factors, including historical practice, individual and company performance and internal pay equity considerations, and are compared against peer group data to ensure the appropriate competitiveness of an NEO’s total cash compensation opportunity. However, as discussed above, AIP target award levels are not targeted at a specific percentile or range of the peer group data, nor was market survey data used in setting AIP target award levels for 2010. Annual incentive target award levels were also consistent with the intent to have a significant portion of NEO compensation at risk. The 2010 AIP targets for the NEOs, as a percentage of their base salary, are shown below and as compared to their 2009 targets.


Name	2009 AIP Target Award*		2010 AIP Target Award*
Thomas F. Farrell II		125%		125%
Mark F. McGettrick		95%		100%
Paul D. Koonce		90%		90%
David A. Christian		80%		85%
James F. Stutts		80%		80%

* As a % of base salary

The 2010 AIP targets for Messrs. Farrell, Koonce and Stutts were the same as their 2009 AIP targets at 125%, 90% and 80% of base salary, respectively.

Mr. McGettrick transitioned from the role of CEO of the Dominion Generation business unit to CFO of Dominion in 2009, but he did not receive an increase in his AIP target in 2009 when he became Dominion’s CFO. Due to Mr. McGettrick’s increased responsibility as Dominion’s CFO, Mr. McGettrick’s 2010 AIP target increased from 95% to 100%. Similarly, Mr. Christian’s AIP target did not increase in 2009 when he transitioned from CNO to CEO of the Generation business unit. Due to the increased scope of responsibility in his new position, the CGN Committee determined it was appropriate to increase the AIP target for 2010 from 80% to 85% for Mr. Christian.

FUNDING OF THE 2010 AIP

Funding of the 2010 AIP was based solely on consolidated operating earnings per share, with potential funding ranging from 0% to 200% of the target funding. Consolidated operating earnings are Dominion’s reported earnings determined in accordance with GAAP, adjusted for certain items. Dominion believes that by placing a focus on pre-established consolidated operating earnings per share targets, it increases employee awareness of the company’s financial objectives and encourages behavior and performance that will help achieve these objectives.

The 2010 AIP had a full funding target of $3.30 consolidated operating earnings per share, the approximate mid-point of

Dominion’s 2010 earnings guidance announced in January 2010. Funding is based on a formula that provides proportionate sharing of consolidated operating earnings between AIP participants and shareholders until the full funding target is achieved. Consolidated operating earnings above the full funding target of $3.30 operating earnings per share are shared equally with shareholders, up to the maximum AIP funding level of 200% at $3.40 operating earnings per share.

Full funding means that the AIP is 100% funded and participants can receive their full targeted AIP payout if they achieve a score of 100% for their particular goal package, as described below in How AIP Payouts Are Determined. At the maximum plan funding level of 200%, participants can earn up to two times their targeted AIP payout, subject to achievement of their individual goal packages.

Dominion’s consolidated operating earnings for the year ended December 31, 2010 were $1.97 billion, or $3.34 per share, as compared to its consolidated reported earnings in accordance with GAAP of $2.81 billion or $4.76 per share.* This resulted in 134% funding for the 2010 AIP.

*Reconciliation of 2010 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 2010 reported earnings, but are excluded from consolidated operating earnings: $1.4 billion net benefit from the sale of Appalachian E&P operations, $206 million charge related to a workforce reduction program, $155 million net loss from the discontinued operations and loss on sale of Peoples, $127 million impairment charge related to certain merchant generation facilities, $57 million charge related to health care legislation changes, and $1 million net expense related to other items.

HOW AIP PAYOUTS ARE DETERMINED

For most officers other than the NEOs, payout of their funded AIP awards for 2010 was subject to the accomplishment of business unit financial and operating and stewardship goals, including a safety goal. The percentage allocated to each category of goals represents the percentage of the funded award subject to the per-

formance of that goal. Officer goals are weighted according to their responsibilities. The overall score cannot exceed 100% scoring.

Business unit financial goals provide a line-of-sight performance target for officers within a business unit and, on a combined basis, support the consolidated operating earnings target for Dominion. Operating and stewardship goals provide line-of-sight performance targets that may not be financial and that can be customized for each individual or by segments of each business unit. Operating and stewardship goals promote Dominion’s core values of safety, ethics, excellence and teamwork, which in turn contribute to Dominion’s financial success.

The AIP is designed so that AIP payouts earned by the NEOs will qualify as tax deductible “performance-based” compensation under Section 162(m) of the Internal Revenue Code (the Code). To preserve the tax deduction for payouts made to the NEOs whose compensation is subject to Code Section 162(m), their payout, if any, is contingent solely on the achievement of the consolidated financial goal (weighted 100%). If the consolidated financial goal is met, the CGN Committee has the authority to exercise negative discretion to lower payouts if additional discretionary goals are adopted and these discretionary goals are not achieved.

For the 2010 AIP, all of the NEOs adopted a discretionary safety goal. Messrs. Koonce, Christian and Stutts adopted discretionary business unit financial goals and Mr. Stutts also adopted discretionary operating and stewardship goals. These goals are described under 2010 AIP Payouts. The table below shows the goal weightings applied to these discretionary goals.

Name

Consolidated
Financial Goal

Business Unit
Financial Goals

Operating/
Stewardship*

Thomas F. Farrell II

95%

Mark F. McGettrick

95%

Paul D. Koonce

65%

30%

David A. Christian

65%

30%

James F. Stutts

40%

30%

* 5% goal weighting is for a safety goal. Mr. Stutts had other non-safety operating and stewardship goals as described below.

The 2010 discretionary business unit financial goals and accomplishment levels for Mr. Koonce (Dominion Virginia Power), Mr. Christian (Dominion Generation) and Mr. Stutts (DRS) were as follows:

Business Unit

Goal

Threshold

(Net Income)

Goal

100% Payout

(Net Income)

Actual

2010

(Net Income)

2010

Accomplishment

(Millions/$)

Dominion Virginia Power

343

429

448

100%

Dominion Generation

1,032

1,290

1,291

100%

DRS⁽¹⁾

589

535

532

100%

⁽¹⁾

Services Company officers and employees carry an expense goal rather than a net income goal.

Amounts earned under the 2010 AIP by NEOs are shown below and are reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

Note: The NEOs included in this table perform services for more than one subsidiary of Dominion. Compensation for the NEOs listed in the table reflects only the appropriate portion related to their service for Virginia Power for the year presented.

Long-Term Incentive Program

OVERVIEW

Dominion’s long-term incentive program focuses on Dominion’s longer-term strategic goals and retention. Since 2006, 50% of Dominion’s long-term incentives have been full value equity awards in the form of restricted stock with time-based vesting and the other 50% have been performance-based awards. Dominion believes restricted stock serves as a strong retention tool and also creates a focus on Dominion’s stock price to further align the interests of officers with the interests of Dominion’s shareholders. For those officers who have made substantial progress toward their share ownership guidelines, 50% of their long-term award is in the form of a cash performance grant. Because officers are expected to retain ownership of shares upon vesting of restricted stock awards, as explained in Share Ownership Guidelines, the long-term cash performance grant balances the program and allows a portion of the long-term incentive award to be accessible to the NEOs during the course of their employment.

The CGN Committee approves long-term incentive awards in January each year with a grant date established in early February. This process ensures incentive-based awards are made at the beginning of the performance period and shortly after the public disclosure of Dominion’s earnings for the prior year. Like the AIP target award levels discussed above, long-term incentive target award levels are established based on a number of factors, including historical practice, individual and company performance, and internal pay equity considerations, and are compared against peer group data to ensure the appropriate competitiveness of an NEO’s total direct compensation opportunity. However, as discussed above, long-term incentive target award levels are not targeted at a specific percentile or range of the peer group data, nor was market survey data a factor in setting long-term incentive target award levels for 2010.

Through 2009, the long-term incentive values for all NEOs, except for Mr. McGettrick, remained at the same target levels as they had been since 2006, which was the first year Dominion granted performance-based awards as part of the long-term incentive compensation program. Mr. McGettrick’s long-term incentive compensation value has remained at the same target level since 2007. The CGN Committee considered the job performance to date of the NEOs, the increased scope of responsibilities assumed and recent promotions or job rotations and determined it was appropriate to increase the target levels for the NEOs’ 2010 long-term incentive awards from their 2006 target level, or in the case of Mr. McGettrick, his 2007 target level.

Information regarding the fair value of 2010 restricted stock grants and target cash performance grants for the NEOs is provided in the Grants of Plan-Based Awards table.

2010 RESTRICTED STOCK GRANTS

All officers received a restricted stock grant on February 1, 2010 based on a stated dollar value. The number of shares awarded was determined by dividing the stated dollar value by the closing price of Dominion’s common stock on January 29, 2010. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2013. Mr. Stutts’ grant vested pro-rata upon his retirement on January 1, 2011 based on a determination by the CEO that Mr. Stutts’ retirement would not be detrimental to the company. Dividends are paid to officers during the restricted period. The grant date fair value of the 2010 restricted stock grant awards made to the NEOs is disclosed in the Grants of Plan-Based Awards table.

2010 PERFORMANCE GRANTS

Most officers, including the NEOs, received cash performance grants on February 1, 2010. Officers who had not achieved 50% of their targeted share ownership guideline received stock-based performance grants. Dividend equivalents are not paid on any performance-based grants. The performance period commenced on January 1, 2010 and will end on December 31, 2011. Mr. Stutts’ payout, if any, under his 2010 performance grant will be determined after the end of the performance period ending December 31, 2011 and will be pro-rated based on his months of service during such period. The 2010 grants are denominated as a target award, with potential payouts ranging from 0-200% of the target based on Dominion’s TSR relative to the peer group of companies selected by the CGN Committee and ROIC, weighted equally.

The TSR metric was selected to focus officers on long-term shareholder value when developing and implementing their strategic plans and in turn, reward management based on the achievement of TSR levels as measured relative to Dominion’s peer companies. The ROIC metric was selected to reward officers for the achievement of expected levels of return on the company’s investments. Dominion believes an ROIC measure encourages management to choose the right investments, and with those investments, to achieve the highest returns possible through prudent decisions, management and control of costs. The target awards of the 2010 performance grants made to the NEOs are disclosed in the Grants of Plan-Based Awards table.

PAYOUT UNDER 2009 PERFORMANCE GRANTS

In February 2011, final payouts were made to officers who received 2009 performance grants, including the NEOs. The 2009 performance grants were based on three goals: TSR for the two-year period ended December 31, 2010 relative to Dominion’s peer group of companies (weighted 50%); ROIC for the same two-year period (weighted 40%); and BVP as of December 31, 2010 (weighted 10%).

Relative TSR (50% weighting). TSR is the difference between the value of a share of common stock at the beginning and end of the two-year performance period, plus dividends paid as if reinvested in stock. For this metric, Dominion’s TSR is compared to TSR levels at its peer companies for the same two-year period. The peer group for the TSR metric for the 2009 performance grant is the same group of companies described above in The Peer Group and Peer Group Comparisons. The relative TSR targets and corresponding payout scores are as follows:


Relative TSR Performance	Percentage Payout of TSR Percentage*
Top Quartile – 75% to 100%		150% – 200%
2^nd Quartile – 50% to 74.9%		100% – 149.9%
3^rd Quartile – 25% to 49.9%		50% – 99.9%
4^th Quartile – below 25%		0%

TSR weighting is interpolated between the top and bottom of the percentages within a quartile. A minimum payment of 25% of the TSR percentage will be made if the TSR performance is at least 10% on a compounded annual basis for the performance period, regardless of relative performance.

Actual relative TSR performance for the 2009-2010 period was in the top quartile.

ROIC (40% weighting). ROIC reflects the company’s total return divided by average invested capital for the performance period. The ROIC goal at target is consistent with the strategic plan/annual business plan as approved by the Board. For this purpose, total return is the company’s consolidated operating earnings plus its after-tax interest and related charges, plus preferred dividends. Dominion designed its 2009 ROIC goals to provide 100% payout if it achieved an average ROIC of 8.86% over the two-year performance period. The ROIC performance targets and corresponding payout scores are as follows:


ROIC Performance	Percentage Payout of ROIC Percentage*
9.26% and above		200%
9.06% – 9.25%		150% –199.9%
8.86% – 9.05%		100% – 149.9%
8.66% – 8.85%		50% – 99.9%
Below 8.66%		0%

ROIC percentage payout is interpolated between the top and bottom of the percentages for any range.

Actual ROIC performance for the 2009-2010 period was 8.82%.

BVP (10% weighting). BVP measures the company’s value according to its balance sheet (the difference between assets

and liabilities) as opposed to the market value of company stock, subject to certain pre-approved exclusions, whether positive or negative, as set forth in the awards. It measures the use of funds as well as the efficiency of issuing stock. The CGN Committee applied a 10% weighting to this measure in order to allow a mix of performance measures while maintaining the desired focus on relative TSR and ROIC. BVP was calculated as common shareholders’ equity divided by the number of outstanding shares as of December 31, 2010. The BVP targets and corresponding payout scores are as follows:


Book Value Performance	Percentage Payout of BVP Percentage*
$22.66 and above		200%
$22.16 – $22.65		150% – 199.9%
$21.66 – $22.15		100% – 149.9%
$21.16 – $21.65		50% – 99.9%
Below $21.16		0%

* BVP percentage payout is interpolated between the top and bottom of the percentages for any range.

Actual BVP for the 2009-2010 period was $21.89.

Based on the achievement of the performance criteria, the CGN Committee approved a 127.6% payout for the 2009 performance grants. The following table summarizes the achievement of the 2009 performance criteria:

Measure

Goal

Weight%

Goal

Achievement%

Payout%

Relative TSR

50%

157.0%

78.5%

ROIC

40%

92.0%

36.8%

BVP

10%

123.4%

12.3%

Combined Overall Performance Score

127.6%

The resulting payout amounts for the NEOs for the 2009 performance grants are shown below and are also reflected in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table.

Name

2009

Performance

Grant Award

Overall

Performance

Score

Calculated

Performance

Grant Payout

Thomas F. Farrell II

840,000

127.6%

1,071,840

Mark F. McGettrick

345,000

127.6%

440,220

Paul D. Koonce

382,500

127.6%

488,070

David A. Christian

172,250

127.6%

219,791

James F. Stutts

105,000

127.6%

133,980

Other Restricted Stock Grant

In December 2010, the CGN Committee approved a restricted stock grant of 28,000 shares to Mr. Farrell to retain and secure his services for the next five years to provide the leadership stability to implement Dominion’s strategic plans. The grant supports CEO succession planning and the vesting terms of the grant further align Mr. Farrell’s interests with the interests of shareholders. The restricted shares are subject to a five-year cliff vesting with all

shares vesting on December 17, 2015 (the Vesting Date). Mr. Farrell will forfeit the restricted stock grant if his employment with Dominion terminates prior to the Vesting Date for any reason other than a change in control, death or disability. In the event of a change in control, death or disability, the restricted shares are subject to vesting on a pro-rated basis. Dividends will be paid on the restricted shares, but will be retained and subject to the same vesting terms as the restricted shares.

Employee and Executive Benefits

Benefit plans and limited perquisites composed the fourth element of the compensation program. These benefits serve as a retention tool and reward long-term employment.

RETIREMENT PLANS

Dominion sponsors two types of tax-qualified retirement plans for eligible employees, including the NEOs: a defined benefit pension plan (the Pension Plan) and a defined contribution 401(k) savings plan (the 401(k) Plan). The NEOs, as employees hired before 2008, are eligible for a pension benefit upon attainment of retirement age based on a formula that takes into account final compensation and years of service. They also receive a cash balance benefit under which the company contributes 2% of each participant’s compensation to a special retirement account, which may be paid in a lump sum or added to the annuity benefit upon retirement. The formula for the Pension Plan is explained in the narrative following the Pension Benefits table. The change in Pension Plan value for 2010 for the NEOs is included in the Summary Compensation Table.

Officers whose matching contributions under the 401(k) Plan are limited by the Internal Revenue Code receive a cash payment to make them whole for the company match lost as a result of these limits. These cash payments are currently taxable. The company matching contributions to the 401(k) Plan and the cash payments of company matching contributions above Internal Revenue Code limits for the NEOs are included in the All Other Compensation column of the Summary Compensation Table and detailed in the footnote for that column.

Dominion also maintains two nonqualified retirement plans, the BRP and the ESRP, for the executives. Unlike the Pension Plan and 401(k) Plan, these plans are unfunded, unsecured obligations of Dominion. These plans keep Dominion competitive in attracting and retaining officers. Due to Internal Revenue Code limits on Pension Plan benefits and because a more substantial portion of total compensation for officers is paid as incentive compensation than for other employees, the Pension Plan and 401(k) Plan alone will produce a lower percentage of replacement income in retirement for officers than these plans will for other employees. The BRP restores benefits that will not be paid under the Pension Plan due to the Internal Revenue Code limits. The ESRP provides a benefit that covers a portion (25%) of final base salary and target annual incentive compensation to partially make up for this gap in retirement income. The BRP and ESRP do not include long-term incentive compensation in benefit calculations and, therefore, a significant portion of the potential compensation for the officers is excluded from calculation in any retirement plan benefit. As consideration for the benefits earned under the BRP and ESRP, all officers agree to comply with confidentiality and one-year non-competition

requirements set forth in the plan documents following their retirement or other termination of employment. The present value of accumulated benefits under these retirement plans is disclosed in the Pension Benefits table and the terms of the plans are fully explained in the narrative following that table.

In May 2010, the CGN Committee entered into a supplemental retirement agreement with Mr. McGettrick. This agreement restates and clarifies the terms of prior agreements entered into in 2005 and 2007 as well as the surviving provisions of his 1999 employment agreement. Mr. McGettrick will earn a lifetime benefit under the ESRP if he remains employed as an officer of Dominion until November 14, 2012, effectively giving him previously earned age and service credit toward the lifetime ESRP benefit that was provided to him under the surviving provisions of his 1999 employment agreement and later restated in a February 2007 letter agreement. As consideration for this benefit, Mr. McGettrick has agreed not to compete with the company for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.

OTHER BENEFIT PROGRAMS

Officers participate in all of the benefit programs available to other employees. The core benefit programs generally include medical, dental and vision benefit plans, a health savings account, health and dependent care flexible spending accounts, group-term life insurance, travel accident coverage, long-term disability coverage and a paid time off program.

Dominion also maintains an executive life insurance program for officers to replace a former company-wide retiree life insurance program that was discontinued in 2003. The plan is fully insured by individual policies that provide death benefits at a fixed amount depending on an officer’s salary tier. This life insurance coverage is in addition to the group-term insurance that is provided to all employees. The officer is the owner of the policy and Dominion makes premium payments until the later of 10 years or the date the officer attains age 64. Officers are taxed on the premiums paid by Dominion. The premiums for these policies are included in the All Other Compensation column of the Summary Compensation Table.

PERQUISITES

Dominion provides a limited number of perquisites for officers to enable them to perform their duties and responsibilities as efficiently as possible and to minimize distractions. The CGN Committee annually reviews the perquisites to ensure they are an effective and efficient use of corporate resources. Dominion believes the benefits it receives from offering these perquisites outweigh the costs of providing them. In addition to incidental perquisites associated with maintaining an office, Dominion offers the following perquisites to all officers:

An allowance of up to $9,500 a year to be used for health club memberships and wellness programs, comprehensive executive physical exams and financial and estate planning. Dominion wants officers to be proactive with preventive healthcare and also wants executives to use professional, independent financial and estate planning consultants to ensure proper tax reporting of company-provided compensation and to help officers optimize their use of Dominion’s retirement and other employee benefit programs.

A vehicle leased by Dominion, up to an established lease-payment limit (if the lease payment exceeds the allowance, the officer pays for the excess amount on the vehicle). The costs of insurance, fuel and maintenance for company-leased vehicles are paid by Dominion.

In limited circumstances, use of company aircraft for personal travel by executive officers. For security and other reasons, the Board has directed Mr. Farrell to use the aircraft for all travel, including personal travel, whenever it is feasible to do so. His family and guests may accompany Mr. Farrell on any personal trips. The use of company aircraft for personal travel by other executive officers is limited and usually related to (i) travel with the CEO or (ii) personal travel to accommodate business demands on an executive’s schedule. With the exception of Mr. Farrell, personal use of aircraft is not available when there is a company need for the aircraft. Use of company aircraft saves substantial time and allows us to have better access to the executives for business purposes. During 2010, 96% of the use of corporate aircraft was for business purposes. Other than Mr. Farrell, none of the NEOs or other executive officers used company aircraft for personal travel in 2010.

Other than costs associated with comprehensive executive physical exams (which are exempt from taxation under the Internal Revenue Code), these perquisites are fully taxable to officers. There is no tax gross-up for imputed income on any perquisites.

EMPLOYMENT CONTINUITY AGREEMENTS

Dominion has entered into Employment Continuity Agreements with all officers to ensure continuity in the event of a change in control of Dominion. While Dominion has determined these agreements are consistent with the practices of its peer companies, the most important reason for these agreements is to protect the company in the event of an anticipated or actual change in control of Dominion. In a time of transition, it is critical to protect shareholder value by retaining and continuing to motivate the company’s core management team. In a change in control situation, workloads typically increase dramatically, outside competitors are more likely to attempt to recruit top performers away from the company, and officers and other key employees may consider other opportunities when faced with uncertainties at their own company. Therefore, the Employment Continuity Agreements provide security and protection to officers in such circumstances for the long-term benefit of the company and its shareholders.

In determining the appropriate multiples of compensation and benefits payable upon a change in control, Dominion evaluated peer group and general practices and considered the levels of protection necessary to retain officers in such situations. The Employment Continuity Agreements are double-trigger agreements that require both a change in control and a qualifying termination of employment to trigger a benefit. The specific terms of the Employment Continuity Agreements are discussed in Additional Post-Employment Benefits for NEOs under Potential Payments Upon Termination or Change in Control.

OTHER AGREEMENTS

Dominion does not have comprehensive employment agreements or severance agreements for its NEOs. Although the CGN Committee believes the compensation and benefit programs described in this CD&A are appropriate, Dominion, as one of the nation’s largest producers and transporters of energy, is part of a constantly changing and increasingly competitive environment. In recognition of their valuable knowledge and experience and to secure and retain their services, Dominion has entered into letter agreements with each of the NEOs to provide certain benefit enhancements or other protections, as described in Additional Post-Employment Benefits for NEOs under Potential Payments Upon Termination or Change in Control.

OTHER RELEVANT COMPENSATION PRACTICES

Share Ownership Guidelines

Dominion requires officers to own and retain significant amounts of Dominion stock during their careers to align their interests with those of Dominion’s shareholders by promoting a long-term focus through long-term share ownership. The guidelines ensure that management maintains a personal stake in Dominion through significant equity investment in Dominion. Targeted ownership levels are the lesser of the following value or number of shares:


Position	Value/# of Shares
Chairman, President & Chief Executive Officer		8 x salary/145,000
Executive Vice President – Dominion		5 x salary/35,000
Senior Vice President – Dominion & Subsidiaries/President – Dominion Subsidiaries		4 x salary/20,000
Vice President – Dominion & Subsidiaries		3 x salary/10,000

The levels of ownership reflect the increasing level of responsibility for that officer’s position. Shares owned by an officer and his or her immediate family members as well as shares held under company benefit plans contribute to the ownership targets. Restricted stock, goal-based stock and shares underlying stock options do not contribute to the ownership targets. Dominion prohibits certain types of transactions related to Dominion stock, including owning derivative securities, hedging transactions, using margin accounts and pledging shares as collateral.

With limited exceptions, officers are expected to retain ownership of their Dominion stock, including restricted stock and goal-based shares that have vested, as long as they remain employed by the company. Dominion refers to shares held by an officer that are more than 15% above his or her ownership target as “Qualifying Excess Shares.” Officers may sell up to 50% of their Qualifying Excess Shares at any time, subject to insider trading rules and other policy provisions, and may sell all Qualifying Excess Shares during the one-year period preceding retirement. Qualifying Excess Shares may also be gifted to a charitable organization or put into a trust outside of the officer’s control for estate planning purposes at any time.

At least annually, the CGN Committee reviews the share ownership guidelines and monitors compliance by executive officers, both individually and by the officer group as a whole. The NEOs’ ownership is shown in the Director and Officer Share Ownership table; each NEO exceeds his ownership target.

Recovery of Incentive Compensation

Consistent with standards established by the Sarbanes-Oxley Act of 2002, Dominion’s Corporate Governance Guidelines authorize the Board to seek recovery of performance-based compensation paid to officers who are found to be personally responsible for fraud or intentional misconduct that causes a restatement of financial results filed with the SEC. Beginning in 2009, the CGN Committee approved a broader clawback provision for inclusion in Dominion’s AIP and long-term incentive performance grant documents. This clawback provision authorizes the CGN Committee, in its discretion and based on facts and circumstances, to recoup AIP and performance grant payouts from any employee whose fraudulent or intentional misconduct (i) directly causes or partially causes the need for a restatement of a financial statement or (ii) relates to or materially affects Dominion’s operations or the employee’s duties at the company. Dominion reserves the right to recover a payout by seeking repayment from the employee, by reducing the amount that would otherwise be payable to the employee under another Dominion benefit plan or compensation program to the extent permitted by applicable law, by withholding future incentive compensation, or any combination of these actions. The clawback provision is in addition to, and not in lieu of, other actions Dominion may take to remedy or discipline misconduct, including termination of employment or a legal action for breach of fiduciary duty, and any actions imposed by law enforcement agencies.

Tax Deductibility of Compensation

Code Section 162(m) generally disallows a deduction by publicly-held corporations for compensation in excess of $1 million paid to the CEO and next three most highly-compensated officers other than the CFO. If certain requirements are met, performance-based compensation qualifies for an exemption from the Code Section 162(m) deduction limit. Dominion intends to provide competitive executive compensation while maximizing Dominion’s tax deduction. While the CGN Committee considers Code Section 162(m) tax implications when designing annual and long-term compensation programs and approving payouts under such programs, it reserves the right to approve, and in some cases has approved, non-deductible compensation when corporate objectives justify the cost of being unable to deduct such compensation. Dominion’s tax department has advised the CGN Committee that the cost of any such lost tax deductions is not material to the company.

Accounting for Stock-Based Compensation

Dominion measures and recognizes compensation expense in accordance with FASB guidance for share-based payments, which requires that compensation expense relating to share-based payment transactions be recognized in the financial statements based on the fair value of the equity or liability instruments issued. The CGN Committee considers the accounting treatment of equity and performance-based compensation when approving awards.

The Summary Compensation Table provides information in accordance with SEC requirements regarding compensation earned by the NEOs, as well as amounts accrued or accumulated during years reported with respect to retirement plans and other items. The NEOs include the CEO, the CFO, and the three most highly compensated executive officers of Virginia Power other than the CEO and CFO.

The amounts reported in the Summary Compensation Table and the other tables below represent the pro-rated compensation amounts attributable to each NEO’s services performed for Virginia Power. The percentage of each NEO’s overall Dominion services performed for Virginia Power during 2010 was as follows: Mr. Farrell, 28%; Mr. McGettrick, 46%; Mr. Koonce, 85%; Mr. Christian, 53%; and Mr. Stutts, 42%.

The following highlights some of the disclosures contained in this table for the NEOs. Detailed explanations regarding certain types of compensation paid to an NEO are included in the footnotes to the table.

Salary. The amounts in this column are the base salaries earned by the NEOs for the years indicated. For 2010, this amount also includes a 2% merit lump sum payment to all NEOs.

Stock Awards. The amounts in this column reflect the full grant date fair value of the stock awards for accounting purposes for the respective year. The amounts shown for 2008 are different from the amounts shown in prior years due to a change in SEC reporting requirements.

Non-Equity Incentive Plan Compensation. This column includes amounts earned under two performance-based programs: the AIP and cash-based performance grant awards under Dominion’s long-term incentive programs. These performance programs are based on performance criteria established by the CGN Committee at the beginning of the performance period, with actual performance scored against the pre-set criteria by the CGN Committee at the end of the performance period.

Change in Pension Value and Nonqualified Deferred Compensation Earnings. This column shows any year-over-year increases in the annual accrual of pension and supplemental retirement benefits for the NEOs. These are accruals for future benefits that may be earned under the terms of the retirement plans, and do not reflect actual payments made during the year to the NEOs. The amounts disclosed reflect the annual change in the actuarial present value of benefits under defined benefit plans sponsored by the

company, which include Dominion’s tax-qualified Pension Plan and the nonqualified plans described in the narrative following the Pension Benefits table. The annual change equals the difference in the accumulated amount for the current fiscal year and the accumulated amount for the prior fiscal year, generally using the same actuarial assumptions used for Dominion’s audited financial statements for the applicable fiscal year. For 2009 and 2010, accrued benefit calculations are based on assumptions that the NEOs would retire at the earliest age at which they are projected to become eligible for full, unreduced pension benefits (including the effect of future service for eligibility purposes), instead of their unreduced retirement age based on current years of service. The application of these assumptions results in a greater increase in the accumulated amount of pension benefits for certain NEOs than would result without the application of these assumptions. This method of calculation does not increase actual benefits payable at retirement but only how much of that benefit is allocated to the increase during 2009 and 2010, respectively. For Mr. McGettrick, the accrued benefit calculation for 2010 also reflects the clarification of the commencement date of his lifetime ESRP benefits. Please refer to the footnotes to the Pension Benefits table and the narrative following that table for additional information related to actuarial assumptions used to calculate pension benefits.

All Other Compensation. The amounts in this column disclose compensation that is not classified as compensation reportable in another column, including perquisites and benefits with an aggregate value of at least $10,000, the value of company-paid life insurance premiums, company matching contributions to an NEO’s 401(k) Plan account, and company matching contributions paid directly to the NEO that would be credited to the 401(k) Plan if Internal Revenue Code contribution limits did not apply. For 2010, dividends paid on outstanding restricted stock are not included in All Other Compensation in accordance with SEC rules as the value of the dividends is factored into the grant date fair value of the restricted stock.

Total. The number in this column provides a single figure that represents the total compensation either earned by each NEO for the years indicated or accrued benefits payable in later years and required to be disclosed by SEC rules in this table. It does not reflect actual compensation paid to the NEO during the year, but is the sum of the dollar values of each type of compensation quantified in the other columns in accordance with SEC rules.

The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2010, 2009 and 2008 as well as the grant date fair value of stock awards and changes in pension value.

The following table provides information about stock awards and non-equity incentive awards granted to the NEOs during the year ended December 31, 2010.

The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2010. There were no unexercised or unexercisable option awards outstanding for any NEOs as of December 31, 2010.

The following table provides information about the value realized by NEOs during the year ended December 31, 2010 on vested restricted stock awards. There were no option exercises by NEOs in 2010.

The following table shows the actuarial present value of accumulated benefits payable to NEOs, together with the number of years of benefit service credited to each NEO, under the plans listed in the table. Values are computed as of December 31, 2010, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in Dominion’s financial statements. The years of credited service and the present value of accumulated benefits used in the table below were determined by our plan actuaries, using the appropriate accrued service and pay and other assumptions similar to those used for accounting and disclosure purposes. Please refer to Actuarial Assumptions Used to Calculate Pension Benefits for detailed information regarding these assumptions.

Dominion Pension Plan

The Dominion Pension Plan is a tax-qualified defined benefit pension plan. All of the NEOs participate in the Pension Plan. The Pension Plan provides unreduced retirement benefits at termination of employment at or after age 65 or, with three years of service, at age 60. A participant who has attained age 55 with three years of service may elect early retirement benefits at a reduced amount. If a participant retires between ages 55 and 60, the benefit is reduced 0.25% per month for each month after age 58 and before age 60, and reduced 0.50% per month for each month between ages 55 and 58. All of the NEOs have more than three years of service.

The Pension Plan basic benefit is calculated using a formula based on (1) age at retirement; (2) final average earnings; (3) estimated Social Security benefits; and (4) credited service. Final average earnings are the average of the participant’s 60 highest consecutive months of base pay during the last 120 months worked. Final average earnings do not include compensation payable under the AIP, the value of equity awards, gains from the exercise of stock options, long-term cash incentive awards, perquisites or any other form of compensation other than base pay.

Credited service is measured in months, up to a maximum of 30 years of credited service. The estimated Social Security benefit taken into account is the assumed Social Security benefit payable starting at age 65 or actual retirement date, if later, assuming that the participant has no further employment after leaving Dominion. These factors are then applied in a formula.

The formula has different percentages for credited service through December 31, 2000 and on and after January 1, 2001. The benefit is the sum of the amounts from the following two formulas.


For Credited Service through December 31, 2000:
2.03% times Final Average Earnings times Credited Service before 2001	Minus	2.00% times estimated Social Security benefit times Credited Service before 2001

For Credited Service on or after January 1, 2001
1.80% times Final Average Earnings times Credited Service after 2000	Minus	1.50% times estimated Social Security benefit times Credited Service after 2000

Credited Service is limited to a total of 30 years for all parts of the formula and Credited Service after 2000 is limited to 30 years minus Credited Service before 2001.

Benefit payment options are (1) a single life annuity or (2) a choice of a 50%, 75% or 100% joint and survivor annuity. A Social Security leveling option is available with any of the benefit forms. The normal form of benefit is a single life annuity for unmarried participants and a 50% joint and survivor annuity for married participants. All of the payment options are actuarially equivalent in value to the single life annuity. The Social Security leveling option pays a larger benefit equal to the estimated Social Security benefit until the participant is age 62 and then reduced payments after age 62.

The DPP also includes a special retirement account, which is in addition to the pension benefit. The special retirement account is credited with 2% of base pay each month as well as interest

based on the 30-year Treasury bond rate set annually (4.19% in 2010). The special retirement account can be paid in a lump sum or paid in the form of an annuity benefit.

A participant becomes vested in his or her benefit after completing three years of service. A vested participant who terminates employment before age 55 can start receiving benefit payments calculated using terminated vested reduction factors at any time after attaining age 55. If payments begin before age 65, then the following reduction factors for the portion of the benefits earned after 2000 apply: age 64 – 9%; age 63 – 16%; age 62 – 23%; age 61 – 30%; age 60 – 35%; age 59 – 40%; age 58 – 44%; age 57 – 48%; age 56 – 52%; and age 55 – 55%.

The Internal Revenue Code limits the amount of compensation that may be included in determining pension benefits under qualified pension plans. For 2010, the compensation limit was $245,000. The Internal Revenue Code also limits the total annual benefit that may be provided to a participant under a qualified defined benefit plan. For 2010, this limitation was the lesser of (i) $195,000 or (ii) the average of the participant’s compensation during the three consecutive years in which the participant had the highest aggregate compensation.

Dominion Retirement Benefit Restoration Plan

The BRP is a nonqualified defined benefit pension plan designed to make up for benefit reductions under the DPP due to the limits imposed by the Internal Revenue Code.

A Dominion employee is eligible to participate in the BRP if (1) he or she is a member of management or a highly compensated employee, (2) his or her DPP benefit is or has been limited by the Internal Revenue Code compensation or benefit limits, and (3) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.

Upon retirement, a participant’s BRP benefit is calculated using the same formula used to determine the participant’s default annuity form of benefit under the DPP (single life annuity for unmarried participants and 50% joint and survivor annuity for married participants), and then subtracting the benefit the participant is entitled to receive under the DPP. To accommodate the enactment of Internal Revenue Code Section 409A, the portion of a participant’s BRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall restoration benefit is not changed.

The restoration benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive a single life or 50% or 100% joint and survivor annuity for the portion of his or her benefit that accrued prior to 2005. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase an annuity contract.

A participant who terminates employment before he or she is eligible for benefits under the DPP generally is not entitled to a restoration benefit. Messrs. Farrell and McGettrick have been granted age and service credits for purposes of calculating their DPP and BRP benefits. Mr. Farrell, having attained age 55, has earned benefits based on 25 years of service; if he remains

employed until age 60, benefits will be calculated based on 30 years of service. Mr. McGettrick, having attained age 50, has earned benefits calculated based on five additional years of age and service. Mr. Stutts, having attained age 65, has earned benefits based on 20 years of service. For each of these NEOs, the additional years of service count for determining both the amount of benefits and the eligibility to receive them. For additional information regarding service credits, see Additional Post-Employment Benefits for NEOs under Potential Payments Upon Termination or Change in Control.

If a vested participant dies when he or she is retirement eligible (on or after age 55), the participant’s beneficiary will receive the restoration benefit in a single lump sum payment. If a participant dies while employed but before he or she has attained age 55 and the participant is married at the time of death, the participant’s spouse will receive a restoration benefit calculated in the same way as the 50% Qualified Pre-Retirement Survivor Annuity payable under the Pension Plan and paid in a lump sum payment.

Dominion Executive Supplemental Retirement Plan

The ESRP is a nonqualified defined benefit plan that provides for an annual retirement benefit equal to 25% of a participant’s final cash compensation (base salary plus target annual incentive award) payable for a period of 10 years or, for certain participants designated by the CGN Committee, for the participant’s lifetime. To accommodate the enactment of Internal Revenue Code Section 409A, the portion of a participant’s ESRP benefit that had accrued as of December 31, 2004 is frozen, but the calculation of the overall benefit is not changed.

A Dominion employee is eligible to participate in the ESRP if (1) he or she is a member of management or a highly-compensated employee, and (2) he or she has been designated as a participant by the CGN Committee. A participant remains a participant until he or she ceases to be eligible for any reason other than retirement or until his or her status as a participant is revoked by the CGN Committee.

A participant is entitled to the full ESRP benefit if he or she separates from service with Dominion after reaching age 55 and achieving 60 months of service. An officer who becomes a participant on or after December 1, 2006, must have reached age 55 and completed 60 months of service as an officer in order to be entitled to a full ESRP benefit. A participant who separates from service with Dominion with at least 60 months of service but who has not yet reached age 55 is entitled to a reduced, pro-rated retirement benefit. A participant who separates from service with Dominion with fewer than 60 months of service is generally not entitled to an ESRP benefit unless the participant separated from service on account of disability or death.

The ESRP benefit is generally paid in the form of a single lump sum cash payment. However, a participant may elect to receive the portion of his or her benefit that had accrued as of December 31, 2004 in monthly installments. The lump sum calculation includes an amount approximately equivalent to the amount of taxes the participant will owe on the lump sum payment so that the participant will have sufficient funds, on an after-tax basis, to purchase a 10-year or lifetime annuity contract.

All of the NEOs except Mr. Koonce are currently entitled to a full ESRP retirement benefit. If Mr. Koonce terminates employment before he attains age 55, he will receive a pro-rated ESRP

benefit. Based on determinations made by the CGN Committee, Messrs. Farrell and Koonce will receive an ESRP benefit calculated as a lifetime benefit, and Mr. McGettrick will receive ESRP benefits calculated as a lifetime benefit provided he remains employed with Dominion until attainment of age 55. Mr. Christian will receive ESRP benefits calculated as a lifetime benefit provided he remains employed with Dominion until attainment of age 60.

Actuarial Assumptions Used to Calculate Pension Benefits

Actuarial assumptions used to calculate DPP benefits are prescribed by the terms of the DPP based on Internal Revenue Code and Pension Benefit Guaranty Corporation requirements. The present value of the accumulated benefit is calculated using actuarial and other factors as determined by the plan actuaries and approved by Dominion. Actuarial assumptions used for the December 31, 2010 benefit calculations shown in the Pension Benefits table use a discount rate of 5.90% to determine the present value of the future benefit obligations for the DPP, BRP and ESRP and a lump sum interest rate of 5.15% to estimate the lump sum values of BRP and ESRP benefits. Each NEO is assumed to retire at the earliest age at which he is projected to become eligible for full, unreduced pension benefits. Beginning with the 2009 calculations, for purposes of estimating future eligibility for unreduced DPP and ESRP benefits, the effect of future service is considered. Each NEO is assumed to commence DPP payments at the same age as BRP payments. The longevity assumption used to determine the present value of benefits is the same assumption used for financial reporting of the DPP liabilities, with no assumed mortality before retirement age. Assumed mortality after retirement is based on tables from the Society of Actuaries’ RP-2000 study, projected from 2000 to 2010 with 50% of the Scale AA factors, and further adjusted for Dominion experience by using an age set-forward factor. For BRP and ESRP benefits, other actuarial assumptions include an assumed tax rate of 40%.

The discount rate for calculating lump sum BRP and ESRP payments at the time an officer terminates employment is selected by Dominion’s Administrative Benefits Committee and adjusted periodically. For 2010, a 5.28% discount rate was used to determine the lump sum payout amounts. For 2010 and later years, the discount rate for each year will be based on a rolling average of the blended rate published by the Pension Benefit Guaranty Corporation in October of the previous five years.

NONQUALIFIED DEFERRED COMPENSATION


Name	Aggregate Earnings in Last FY* (as of 12/31/2010)		Aggregate Balance at Last FYE (as of 12/31/2010)
Thomas F. Farrell II	$	1,305	$	3,900
Mark F. McGettrick		39,837		354,081
Paul D. Koonce		86,965		987,292
David A. Christian		636		14,957
James F. Stutts		32,207		250,851

*	No preferential earnings are paid and therefore no earnings from these plans are included in the Summary Compensation Table.

At this time, Dominion does not offer any nonqualified elective deferred compensation plans to its officers or other employees. The Nonqualified Deferred Compensation table reflects, in aggregate, the plan balances for two former plans offered to officers and other highly compensated employees: Dominion Resources, Inc. Executives’ Deferred Compensation Plan (Frozen Deferred Compensation Plan) and Dominion Resources, Inc. Security Option Plan (Frozen DSOP), which were frozen as of December 31, 2004. Although the Frozen DSOP was an option plan rather than a deferred compensation plan, Dominion is including information regarding the plan and any balances in this table to make full disclosure about possible future payments to officers under Dominion’s employee benefit plans.

The Frozen Deferred Compensation Plan includes amounts previously deferred from one of the following categories of compensation: (i) salary; (ii) bonus; (iii) vesting restricted stock, and (iv) gains from stock option exercises. The plan also provided for company contributions of lost company 401(k) Plan match contributions and transfers from several CNG deferred compensation plans. The Frozen Deferred Compensation Plan offers 28 investment funds for the plan balances, including a Dominion Stock Fund. Participants may change investment elections on any business day. Any vested restricted stock and gains from stock option exercises that were deferred were automatically allocated to the Dominion Stock Fund and this allocation cannot be changed. Earnings are calculated based on the performance of the underlying investment fund.

The NEOs invested in the following funds with rates of returns for 2010 as follows: Vanguard 500 Index Fund, 14.9%; Dominion Resources Stock Fund, 14.47%; and Dominion Fixed Income Fund, 4.19%. The Vanguard 500 Index Fund has the same rate of return as the corresponding publicly available mutual fund.

The Dominion Fixed Income Fund is an investment option that provides a fixed rate of return each year based on a formula that is tied to the adjusted federal long-term rate published by the IRS in November prior to the beginning of the year. Dominion’s Asset Management Committee determines the rate based on its estimate of the rate of return on Dominion assets in the trust for the Frozen Deferred Compensation Plan.

The default Benefit Commencement Date is February 28 after the year in which the participant retires, but the participant may select a different Benefit Commencement Date in accordance with the plan. Participants may change their Benefit Commencement Date election; however, a new election must be made at least six months before an existing Benefit Commencement Date. Withdrawals less than six months prior to an existing Benefit Commencement Date are subject to a 10% early withdrawal penalty. Account balances must be fully paid out no later than the February 28 that is 10 calendar years after a participant retires or becomes disabled. If a participant retires from Dominion, he or she may continue to defer an account balance provided that the total balance is distributed by this deadline. In the event of termination of employment for reasons other than death, disability or retirement before an elected Benefit Commencement Date, benefit payments will be distributed in a lump sum as soon as administratively practicable. Hardship distributions, prior to an elected Benefit Commencement Date, are available under certain limited circumstances.

Participants may elect to have their benefit paid in a lump sum payment or equal annual installments over a period of whole years from one to 10 years. Participants have the ability to change their distribution schedule for benefits under the plan by giving six months notice to the plan administrator. Once a participant begins receiving annual installment payments, the participant can make a one-time election to either (1) receive the remaining account balance in the form of a lump sum distribution or (2) change the remaining installment payment period. Any election must be approved by the company before it is effective. All distributions are made in cash with the exception of the Deferred Restricted Stock Account and the Deferred Stock Option Account, which are distributed in the form of Dominion common stock.

The Frozen DSOP enabled employees to defer all or a portion of their salary and bonus and receive options on various mutual funds. Participants also received lost company matching contributions to the 401(k) Plan in the form of options under this plan. DSOP options can be exercised at any time before their expiration date. On exercise, the participant receives the excess of the value, if any, of the underlying mutual funds over the strike price. The participant can currently choose among options on 27 mutual funds, and there is not a Dominion stock alternative or a fixed income fund. Participants may change options among the mutual funds on any business day. Benefits grow/decline based on the total return of the mutual funds selected. Any options that expire do not have any value. Options expire under the following terms:

Options expire on the last day of the 120th month after retirement or disability;

Options expire on the last day of the 24th month after the participant’s death (while employed);

Options expire on the last day of the 12th month after the participant’s severance;

Options expire on the 90th day after termination with cause; and

Options expire on the last day of the 120th month after severance following a change in control.

The NEOs held options on the following publicly available mutual funds, which had rates of return for 2010 as noted.


Fund	Rate of Return
Vanguard Developed Markets Index		8.5%
Vanguard Extended Market Index		27.4%
Vanguard Short-Term Bond Index		3.9%
Vanguard Small Cap Growth Index		30.7%
Vanguard US Value Fund		13.8%
Artisan International Investor		5.9%
Dodge & Cox Balanced		12.2%
Harbor International Fund		12.0%
Janus Growth & Income Fund		8.6%
Perkins Mid Cap Value Investor		14.8%

POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL

Under certain circumstances, Dominion provides benefits to eligible employees upon termination of employment, including a termination of employment involving a change in control of the

company, that are in addition to termination benefits for other employees in the same situation.

Change in Control

As discussed in the Employee and Executive Benefits section of the CD&A, Dominion has entered into an Employment Continuity Agreement with each of its officers, including the NEOs. Each agreement has a three-year term and is automatically extended annually for an additional year, unless cancelled by Dominion.

The Employment Continuity Agreements require two triggers for the payment of most benefits:

There must be a change in control; and

The executive must either be terminated without cause, or terminate his or her employment with the surviving company after a “constructive termination.” Constructive termination means the executive’s salary, incentive compensation or job responsibility is reduced after a change in control or the executive’s work location is relocated more than 50 miles without his or her consent.

For purposes of the Employment Continuity Agreements, a change in control will occur if (i) any person or group becomes a beneficial owner of 20% or more of the combined voting power of Dominion voting stock or (ii) as a direct or indirect result of, or in connection with, a cash tender or exchange offer, merger or other business combination, sale of assets, or contested election, the directors constituting the Dominion Board before any such transaction cease to represent a majority of Dominion’s or its successor’s Board within two years after the last of such transactions.

If an executive’s employment following a change in control is terminated without cause or due to a constructive termination, the executive will become entitled to the following termination benefits:

Lump sum severance payment equal to three times base salary plus AIP award (determined as the greater of (i) the target annual award for the current year or (ii) the highest actual AIP payout for any one of the three years preceding the year in which the change in control occurs).

Full vesting of benefits under ESRP and BRP with five years of additional credited age and five years of additional credited service from the change in control date.

Group-term life insurance. If the officer elects to convert group-term insurance to an individual policy, the company pays the premiums for 12 months.

Executive life insurance. Premium payments will continue to be paid by Dominion until the earlier of: (1) the fifth anniversary of the termination date, or (2) the later of the 10th anniversary of the policy or the date the officer attains age 64.

Retiree medical coverage will be determined under the relevant plan with additional age and service credited as provided under an officer’s letter agreement (if any) and including five additional years credited to age and five additional years credited to service.

Outplacement services for one year (up to $25,000).

If any payments are classified as “excess parachute payments” for purposes of Internal Revenue Code Section 280G and the

executive incurs the excise tax, Dominion will pay the executive an amount equal to the 280G excise tax plus a gross-up multiple.

The terms of awards made under the LTIP, rather than the terms of Employment Continuity Agreements, will determine the vesting of each award in the event of a change in control. These provisions are described in the Long-Term Incentive Program section of the CD&A.

Additional Post-Employment Benefits for NEOs

Under the terms of letter agreements with the NEOs, the following benefits are available in addition to the benefits described above. These benefits are quantified in the table below to the extent they would be payable if the triggering event set forth in the table occurred on December 31, 2010.

Mr. Farrell. Mr. Farrell has earned a lifetime benefit under the ESRP. For purposes of calculating his benefits under the DPP and BRP, Mr. Farrell has earned 25 years of credited service as he has met the requirement of remaining employed until he attained age 55. He will be credited with 30 years of service if he remains employed until he attains age 60. Mr. Farrell will become entitled to a payment of one times salary upon his retirement as consideration for his agreement not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.

Mr. McGettrick. Mr. McGettrick will earn a lifetime benefit under the ESRP if he remains employed until he attains age 55. He has earned five years of additional age and service credit for purposes of computing his retirement benefits and eligibility for benefits under the ESRP, long-term incentive grants, and retiree medical and life insurance plans as he has met the requirement of remaining employed until he attained age 50. If Mr. McGettrick terminates employment before he attains age 55, he will be deemed to have retired for purposes of determining his vesting credit under the terms of his restricted stock and performance grant awards.

Mr. Koonce. Mr. Koonce earned a lifetime benefit under the ESRP in early 2010 upon his attainment of age 50. If Mr. Koonce leaves Dominion before age 55, he will be entitled to a pro-rated ESRP benefit.

Mr. Christian. Mr. Christian will earn a lifetime benefit under the ESRP if he remains employed with Dominion until he attains age 60. As consideration for this benefit, Mr. Christian has agreed not to compete with Dominion for a two-year period following retirement. This agreement ensures that his knowledge and services will not be available to competitors for two years following his retirement date.

Mr. Stutts. Mr. Stutts joined Dominion mid-career in 1997. At the time of his employment, Dominion agreed to credit him with 20 years of service (eight additional years) if he remained employed until he attained age 65 for purposes of computing his retirement benefits under the Pension Plan and BRP; he has attained age 65. Mr. Stutts retired effective January 1, 2011.

The table below provides the incremental payments that would be earned by each NEO if his employment had been terminated, or constructively terminated, as of December 31, 2010. These benefits are in addition to retirement benefits that would be payable on any termination of employment. Please refer to the Pension Benefits table for information related to the present value of accumulated retirement benefits payable to the NEOs.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

DOMINION

The information concerning stock ownership by directors, executive officers and five percent beneficial owners contained under the headings Director and Officer Share Ownership and Significant Shareholders in the 2011 Proxy Statement is incorporated by reference.

The information regarding equity securities of Dominion that are authorized for issuance under its equity compensation plans contained under the heading Executive Compensation-Equity Compensation Plans in the 2011 Proxy Statement is incorporated by reference.

VIRGINIA POWER

The table below sets forth as of February 18, 2011, the number of shares of Dominion common stock owned by the executive officers named on the Summary Compensation Table and directors. Dominion owns all of the outstanding common stock of Virginia Power. None of the executive officers or directors own any of the outstanding preferred stock of Virginia Power.

Name of Beneficial Owner

Restricted
Shares

Total⁽¹⁾

Thomas F. Farrell II

469,137

432,553

901,690

Mark F. McGettrick

123,411

86,678

210,089

Steven A. Rogers

40,870

17,953

58,823

David A. Christian

67,126

41,463

108,589

Paul D. Koonce

90,514

51,748

142,262

James F. Stutts

91,096

—

91,096

All directors and executive officers as a group (8 persons)⁽²⁾

869,542

680,341

1,549,883

(1)

Includes shares as to which individuals will acquire beneficial ownership upon distribution from the Dominion Resources, Inc. Executives’ Deferred Compensation Plan, as well as shares as to which voting and/or investment power is shared with or controlled by another person as follows: Mr. Rogers, 617 (shares held in joint tenancy).

(2)

Total does not include shares beneficially owned by James F. Stutts, who retired as of January 1, 2011. Neither any individual director or executive officer, nor all of the directors and executive officers as a group, own more than one percent of Dominion common shares outstanding as of February 18, 2011.

Item 13. Certain Relationships and Related Transactions, and Director Independence

DOMINION

The information regarding related party transactions required by this item found under the heading Related Party Transactions, and information regarding director independence found under the heading Director Independence, in the 2011 Proxy Statement is incorporated by reference.

VIRGINIA POWER

Related Party Transactions

Virginia Power’s Board has adopted the Related Party Guidelines also approved by Dominion’s Board of Directors. These guide-

lines were adopted for the purpose of identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between Virginia Power and any related persons. Under the guidelines, a related person is a director, executive officer, director nominee, a beneficial owner of more than 5% of Dominion’s common stock, or any immediate family member of one of the foregoing persons. A related party transaction is any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships in excess of $120,000 in which Virginia Power (and/or any of its consolidated subsidiaries) is a party and in which the related person has or will have a direct or indirect material interest.

In determining whether a direct or indirect interest is material, the significance of the information to investors in light of all circumstances is considered. The importance of the interest to the person having the interest, the relationship of the parties to the transaction with each other and the amount involved are also among the factors considered in determining the significance of the information to the investors.

Dominion’s CGN Committee has reviewed certain categories of transactions and determined that transactions between Dominion and a related person that fall within such categories will not result in the related person receiving a direct or indirect material interest. Under the guidelines, such transactions are not deemed related party transactions and therefore not subject to review by the CGN Committee. The categories of excluded transactions include, among other items, compensation and expense reimbursement paid to directors and executive officers in the ordinary course of performing their duties; transactions with other companies where the related party’s only relationship is as an employee, if the aggregate amount involved does not exceed the greater of $1 million or 2% of that company’s gross revenues; and charitable contributions which are less than the greater of $1 million or 2% of the charity’s annual receipts. The full text of the guidelines can be found on Dominion’s website at www.dom.com/investors/corporate-governance/pdf/related_party_guidelines.pdf.

Virginia Power collects information about potential related party transactions in its annual questionnaires completed by directors and executive officers. The General Counsel and the Chief Legal Officer review the potential related party transactions and assess whether any of the identified transactions constitute a related party transaction. Any identified related party transactions are then reported to Dominion’s CGN Committee. Dominion’s CGN Committee reviews and considers relevant facts and circumstances and determines whether to ratify or approve the related party transactions identified. Dominion’s CGN Committee may only approve or ratify related party transactions that are in, or are not inconsistent with, the best interests of Dominion and its shareholders and are in compliance with Virginia Power’s Code of Ethics.

Since January 1, 2010 there have been no related party transactions involving Virginia Power that were required either to be approved under Virginia Power’s policies or reported under the SEC related party transactions rules.

Director Independence

Under NYSE listing standards, Messrs. Farrell, McGettrick and Rogers are not independent as they are executive officers of Virginia Power or of its parent company, Dominion. All of Virginia Power’s outstanding common stock is owned by Dominion and therefore, Virginia Power is a “controlled” company under the rules of the NYSE. Because Virginia Power meets the definition of a “controlled company” and has only debt securities and preferred stock listed on the NYSE, it is exempt under Section 303A of the New York Stock Exchange Rules from the provisions relating to board committees and the requirement to have a majority of its board be independent.

Item 14. Principal Accountant Fees and Services

DOMINION

The information concerning principal accounting fees and services contained under the heading Fees and Pre-Approval Policy in the 2011 Proxy Statement is incorporated by reference.

VIRGINIA POWER

The following table presents fees paid to Deloitte & Touche LLP for the fiscal years ended December 31, 2010 and 2009.


Type of Fees	2010		2009
(millions)
Audit fees	$	1.36	$	1.44
Audit-related fees		—		—
Tax fees		—		—
All other fees		—		—
	$	1.36	$	1.44

Audit Fees represent fees of Deloitte & Touche LLP for the audit of Virginia Power’s annual consolidated financial statements, the review of financial statements included in Virginia Power’s quarterly Form 10-Q reports, and the services that an independent auditor would customarily provide in connection with subsidiary audits, statutory requirements, regulatory filings, and similar engagements for the fiscal year, such as comfort letters, attest services, consents, and assistance with review of documents filed with the SEC.

Audit-Related Fees consist of assurance and related services that are reasonably related to the performance of the audit or review of Virginia Power’s consolidated financial statements or internal control over financial reporting. This category may include fees related to the performance of audits and attest services not required by statute or regulations, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of GAAP to proposed transactions.

Virginia Power’s board has adopted Dominion’s Audit Committee Pre-Approval Policy for its independent auditor’s services and fees and has delegated the execution of this policy to Dominion’s audit committee (DRI Audit Committee). In accordance with this delegation, each year the DRI Audit Committee pre-approves a schedule that details the services to be provided for the following year and an estimated charge for such services. At its December 2010 meeting, the DRI Audit Committee approved Virginia Power’s schedule of services and fees for 2011. In accordance with the pre-approval policy, any changes to the pre-approved schedule may be pre-approved by the DRI Audit Committee or a member of this committee.

(a) Certain documents are filed as part of this Form 10-K and are incorporated by reference and found on the pages noted.

1. Financial Statements

See Index on page 53.

2. All schedules are omitted because they are not applicable, or the required information is either not material or is shown in the financial statements or the related notes.

3. Exhibits (incorporated by reference unless otherwise noted)


Exhibit Number	Description	Dominion		Virginia Power
2	Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).		X

3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X

3.1.b	Virginia Electric and Power Company Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-2255).				X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 18, 2010 (Exhibit 3.2, Form 8-K filed May 20, 2010, File No. 1-8489).		X

3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).				X

4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.		X		X

4.1.a	See Exhibit 3.1.a above.		X

4.1.b	See Exhibit 3.1.b above.				X

4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255); Form of Eighty-Fifth Supplemental Indenture, dated February 1, 1997 (Exhibit 4(i), Form 8-K filed February 20, 1997, File No. 1-2255).		X		X

4.3	Subordinated Note Indenture, dated August 1, 1995 between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank)), as Trustee (Exhibit 4(a), Form S-3 Registration Statement filed January 28, 1997, File No. 333-20561), Form of Second Supplemental Indenture, dated August 1, 2002 (Exhibit 4.6, Form 8-K filed August 20, 2002, File No. 1-2255).		X		X

4.4	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated		X		X


Exhibit Number	Description	Dominion		Virginia Power
	December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255).

4.5	Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489).		X

4.6	Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.7	Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.8	Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489);		X


Exhibit Number	Description	Dominion		Virginia Power
	Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489).

4.9	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.10	Form of Indenture for Junior Subordinated Debentures, dated October 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.2, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K filed October 16, 2001, File No. 1-3196); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.8, Form 8-K filed July 3, 2007, File No. 1-8489).		X


Exhibit Number	Description	Dominion		Virginia Power
4.11	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489).		X

4.12	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489).		X

4.13	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489).		X

4.14	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489).		X

10.1	DRI Services Agreement, dated January 28, 2000, by and between Dominion Resources, Inc., Dominion Resources Services, Inc. and Consolidated Natural Gas Service Company, Inc. (Exhibit 10(vii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-8489).		X

10.2	Services Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-2255).		X		X

10.3	Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).		X		X

10.6	$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. 1-8489).		X		X

10.7	$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File No. 1-8489).		X		X

10.8	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-8489).		X		X

10.10*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.11*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255).		X		X

10.12*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).		X		X

10.13*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X


Exhibit Number	Description	Dominion		Virginia Power
10.14*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.15*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).		X		X

10.16*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255).		X		X

10.17*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).		X

10.18*	Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).		X

10.19*	Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).		X

10.20*	Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).		X

10.21*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255).		X		X

10.22*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (filed herewith).		X

10.23*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.24*	Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).		X

10.25*	Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).		X


Exhibit Number	Description	Dominion		Virginia Power

10.26*	Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).		X

10.27*	Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).		X

10.28*	Letter Agreement between Consolidated Natural Gas Company and George A. Davidson, Jr. dated December 22, 1998, related letter dated January 8, 1999 and Amendment to Letter Agreement dated February 26, 2008 (Exhibit 10.37, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489).		X

10.29*	Form of Restricted Stock Grant under 2006 Long-Term Compensation Program approved March 31, 2006 (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489).		X		X

10.30*	Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489).		X		X

10.31*	Form of Performance Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.2, Form 8-K filed April 5, 2007, File No. 1-8489).		X		X

10.32*	Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489).		X		X

10.33*	2008 Performance Grant Plan under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.2, Form 8-K filed April 2, 2008, File No. 1-8489).		X		X

10.34*	Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).		X		X

10.35*	2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X

10.36*	Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X

10.37*	Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective May 5, 2009 (Exhibit 10, Form 8-K filed May 11, 2009, File No. 1-8489), as amended December 17, 2010 (filed herewith).		X		X

10.38*	2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X

10.39*	Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X

10.40*	Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X		X

10.41*	2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X

10.42*	Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X

10.43*	Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).		X		X

10.44*	Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).		X


Exhibit Number	Description	Dominion		Virginia Power
10.45*	Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).		X

10.46*	Restricted Stock Award Agreement for Gary L. Sypolt approved September 24, 2010 (filed herewith).		X

12.a	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).		X

12.b	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).				X

12.c	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).				X

21	Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).		X		X

23	Consent of Deloitte & Touche LLP (filed herewith).		X		X

31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).				X

31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).				X

32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).				X

101^	The following financial statements from Dominion Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 28, 2011, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, (vi) the Notes to Consolidated Financial Statements.		X

*	Indicates management contract or compensatory plan or arrangement

This exhibit will not be deemed “filed” for purposes of Section 18 of the Securities Exchange Act of 1934 (15 U.S.C. 78r), or otherwise subject to the liability of that section. Such exhibit will not be deemed to be incorporated by reference into any filing under the Securities Act or Securities Exchange Act, except to the extent that one of the Companies specifically incorporates it by reference.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on the 28th day of February, 2011.

VIRGINIA POWER


VIRGINIA ELECTRIC AND POWER COMPANY

By:		/S/ THOMAS F. FARRELL II
		(Thomas F. Farrell II, Chairman of the Board of Directors and Chief Executive Officer)

Date: February 28, 2011


Signature		Title

/S/ THOMAS F. FARRELL II Thomas F. Farrell II		Chairman of the Board of Directors and Chief Executive Officer

/S/ MARK F. MCGETTRICK Mark F. McGettrick		Director, Executive Vice President and Chief Financial Officer

/S/ ASHWINI SAWHNEY Ashwini Sawhney		Vice President—Accounting (Chief Accounting Officer)

/S/ STEVEN A. ROGERS Steven A. Rogers		Director


Exhibit Number	Description	Dominion		Virginia Power
2	Purchase and Sale Agreement between Dominion Resources, Inc., Dominion Energy, Inc., Dominion Transmission, Inc. and CONSOL Energy Holdings LLC VI (Exhibit 99.1, Form 8-K filed March 15, 2010, File No. 1-8489).		X

3.1.a	Dominion Resources, Inc. Articles of Incorporation as amended and restated effective May 20, 2010 (Exhibit 3.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X

3.1.b	Virginia Electric and Power Company Restated Articles of Incorporation, as in effect on October 28, 2003 (Exhibit 3.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-2255).				X

3.2.a	Dominion Resources, Inc. Amended and Restated Bylaws, effective May 18, 2010 (Exhibit 3.2, Form 8-K filed May 20, 2010, File No. 1-8489).		X

3.2.b	Virginia Electric and Power Company Amended and Restated Bylaws, effective June 1, 2009 (Exhibit 3.1, Form 8-K filed June 3, 2009, File No. 1-2255).				X

4	Dominion Resources, Inc. and Virginia Electric and Power Company agree to furnish to the Securities and Exchange Commission upon request any other instrument with respect to long-term debt as to which the total amount of securities authorized does not exceed 10% of either of their total consolidated assets.		X		X

4.1.a	See Exhibit 3.1.a above.		X

4.1.b	See Exhibit 3.1.b above.				X

4.2	Indenture of Mortgage of Virginia Electric and Power Company, dated November 1, 1935, as supplemented and modified by Fifty-Eighth Supplemental Indentures (Exhibit 4(ii), Form 10-K for the fiscal year ended December 31, 1985, File No. 1-2255); Eighty-First Supplemental Indenture, (Exhibit 4(iii), Form 10-K for the fiscal year ended December 31, 1993, File No. 1-2255); Form of Eighty-Fifth Supplemental Indenture, dated February 1, 1997 (Exhibit 4(i), Form 8-K filed February 20, 1997, File No. 1-2255).		X		X

4.3	Subordinated Note Indenture, dated August 1, 1995 between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Chemical Bank)), as Trustee (Exhibit 4(a), Form S-3 Registration Statement filed January 28, 1997, File No. 333-20561), Form of Second Supplemental Indenture, dated August 1, 2002 (Exhibit 4.6, Form 8-K filed August 20, 2002, File No. 1-2255).		X		X

4.4	Form of Senior Indenture, dated June 1, 1998, between Virginia Electric and Power Company and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed February 27, 1998, File No. 333-47119); Form of First Supplemental Indenture, dated June 1, 1998 (Exhibit 4.2, Form 8-K filed June 12, 1998, File No. 1-2255); Form of Second Supplemental Indenture, dated June 1, 1999 (Exhibit 4.2, Form 8-K filed June 4, 1999, File No. 1-2255); Form of Third Supplemental Indenture, dated November 1, 1999 (Exhibit 4.2, Form 8-K filed October 27, 1999, File No. 1-2255); Forms of Fourth and Fifth Supplemental Indentures, dated March 1, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed March 26, 2001, File No. 1-2255); Form of Sixth Supplemental Indenture, dated January 1, 2002 (Exhibit 4.2, Form 8-K filed January 29, 2002, File No. 1-2255); Seventh Supplemental Indenture, dated September 1, 2002 (Exhibit 4.4, Form 8-K filed September 11, 2002, File No. 1-2255); Form of Eighth Supplemental Indenture, dated February 1, 2003 (Exhibit 4.2, Form 8-K filed February 27, 2003, File No. 1-2255); Forms of Ninth and Tenth Supplemental Indentures, dated December 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed December 4, 2003, File No. 1-2255); Form of Eleventh Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 11, 2003, File No. 1-2255); Forms of Twelfth and Thirteenth Supplemental Indentures, dated January 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed January 12, 2006, File No. 1-2255); Form of Fourteenth Supplemental Indenture, dated May 1, 2007 (Exhibit 4.2, Form 8-K filed May 16, 2007, File No. 1-2255); Form of Fifteenth Supplemental Indenture, dated September 1, 2007 (Exhibit 4.2, Form 8-K filed September 10, 2007, File No. 1-2255); Forms of Sixteenth and Seventeenth Supplemental Indentures, dated November 1, 2007 (Exhibits 4.2 and 4.3, Form 8-K filed November 30, 2007, File No. 1-2255); Form of Eighteenth Supplemental Indenture, dated April 1, 2008 (Exhibit 4.2, Form 8-K filed April 15, 2008, File No. 1-2255); Form of Nineteenth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 5, 2008, File No. 1-2255); Form of Twentieth Supplemental Indenture, dated June 1, 2009 (Exhibit 4.3, Form 8-K filed June 24, 2009, File No. 1-2255); Form of Twenty-First Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 1, 2010, File No. 1-2255).		X		X


Exhibit Number	Description	Dominion		Virginia Power

4.5	Indenture, Junior Subordinated Debentures, dated December 1, 1997, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)) as supplemented by a First Supplemental Indenture, dated December 1, 1997 (Exhibit 4.1 and Exhibit 4.2 to Form S-4 Registration Statement filed April 22, 1998, File No. 333-50653); Forms of Second and Third Supplemental Indentures, dated January 1, 2001 (Exhibits 4.6 and 4.13, Form 8-K filed January 12, 2001, File No. 1-8489).		X

4.6	Indenture, dated May 1, 1971, between Consolidated Natural Gas Company and The Bank of New York (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank and Manufacturers Hanover Trust Company)) (Exhibit (5) to Certificate of Notification at Commission File No. 70-5012); Fifteenth Supplemental Indenture, dated October 1, 1989 (Exhibit (5) to Certificate of Notification at Commission File No. 70-7651); Seventeenth Supplemental Indenture, dated August 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Eighteenth Supplemental Indenture, dated December 1, 1993 (Exhibit (4) to Certificate of Notification at Commission File No. 70-8167); Nineteenth Supplemental Indenture, dated January 28, 2000 (Exhibit (4A)(iii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Twentieth Supplemental Indenture, dated March 19, 2001 (Exhibit 4.1, Form 10-Q for the quarter ended September 30, 2003 filed November 7, 2003, File No. 1-3196); Twenty-First Supplemental Indenture, dated June 27, 2007 (Exhibit 4.2, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.7	Indenture, dated April 1, 1995, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to United States Trust Company of New York) (Exhibit (4), Certificate of Notification No. 1 filed April 19, 1995, File No. 70-8107); First Supplemental Indenture dated January 28, 2000 (Exhibit (4A)(ii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196); Securities Resolution No. 1 effective as of April 12, 1995 (Exhibit 2, Form 8-A filed April 21, 1995, File No. 1-3196 and relating to the 7 3/8% Debentures Due April 1, 2005); Securities Resolution No. 2 effective as of October 16, 1996 (Exhibit 2, Form 8-A filed October 18, 1996, File No. 1-3196 and relating to the 6 7/8% Debentures Due October 15, 2006); Securities Resolution No. 3 effective as of December 10, 1996 (Exhibit 2, Form 8-A filed December 12, 1996, File No. 1-3196 and relating to the 6 5/8% Debentures Due December 1, 2008); Securities Resolution No. 4 effective as of December 9, 1997 (Exhibit 2, Form 8-A filed December 12, 1997, File No. 1-3196 and relating to the 6.80% Debentures Due December 15, 2027); Securities Resolution No. 5 effective as of October 20, 1998 (Exhibit 2, Form 8-A filed October 22, 1998, File No. 1-3196 and relating to the 6% Debentures Due October 15, 2010); Securities Resolution No. 6 effective as of September 21, 1999 (Exhibit 4A(iv), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-3196, and relating to the 7 1/4% Notes Due October 1, 2004); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.4, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.8	Form of Senior Indenture, dated June 1, 2000, between Dominion Resources, Inc. and The Bank of New York Mellon (as successor trustee to JP Morgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4(iii), Form S-3 Registration Statement filed December 21, 1999, File No. 333-93187); Form of First Supplemental Indenture, dated June 1, 2000 (Exhibit 4.2, Form 8-K filed June 22, 2000, File No. 1-8489); Forms of Second and Third Supplemental Indentures, dated July 1, 2000 (Exhibits 4.2 and 4.3, Form 8-K filed July 11, 2000, File No. 1-8489); Fourth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.2, Form 8-K filed September 8, 2000, File No. 1-8489); Sixth Supplemental Indenture, dated September 1, 2000 (Exhibit 4.3, Form 8-K filed September 11, 2000, File No. 1-8489); Form of Seventh Supplemental Indenture, dated October 1, 2000 (Exhibit 4.2, Form 8-K filed October 12, 2000, File No. 1-8489); Form of Eighth Supplemental Indenture, dated January 1, 2001 (Exhibit 4.2, Form 8-K filed January 24, 2001, File No. 1-8489); Form of Ninth Supplemental Indenture, dated May 1, 2001 (Exhibit 4.4, Form 8-K filed May 25, 2001, File No. 1-8489); Form of Tenth Supplemental Indenture, dated March 1, 2002 (Exhibit 4.2, Form 8-K filed March 18, 2002, File No. 1-8489); Form of Eleventh Supplemental Indenture, dated June 1, 2002 (Exhibit 4.2, Form 8-K filed June 25, 2002, File No. 1- 8489); Form of Twelfth Supplemental Indenture, dated September 1, 2002 (Exhibit 4.2, Form 8-K filed September 11, 2002, File No. 1-8489); Thirteenth Supplemental Indenture, dated September 16, 2002 (Exhibit 4.1, Form 8-K filed September 17, 2002, File No. 1-8489); Fourteenth Supplemental Indenture, dated August 1, 2003 (Exhibit 4.4, Form 8-K filed August 20, 2003, File No. 1-8489); Forms of Fifteenth and Sixteenth Supplemental Indentures, dated December 1, 2002 (Exhibits 4.2 and 4.3, Form 8-K filed December 13, 2002, File No. 1-8489); Forms of Seventeenth and Eighteenth		X


Exhibit Number	Description	Dominion		Virginia Power
	Supplemental Indentures, dated February 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed February 11, 2003, File No. 1-8489; Forms of Twentieth and Twenty-First Supplemental Indentures, dated March 1, 2003 (Exhibits 4.2 and 4.3, Form 8-K filed March 4, 2003, File No. 1-8489); Form of Twenty-Second Supplemental Indenture, dated July 1, 2003 (Exhibit 4.2, Form 8-K filed July 22, 2003, File No. 1-8489); Form of Twenty-Third Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed December 10, 2003, File No. 1-8489); Forms of Twenty-Fifth and Twenty-Sixth Supplemental Indentures, dated January 1, 2004 (Exhibits 4.2 and 4.3, Form 8-K filed January 14, 2004, File No. 1-8489); Form of Twenty-Seventh Supplemental Indenture, dated December 1, 2004 (Exhibit 4.2, Form S-4 Registration Statement filed November 10, 2004, File No. 333-120339); Forms of Twenty-Eighth and Twenty-Ninth Supplemental Indentures, dated June 1, 2005 (Exhibits 4.2 and 4.3, Form 8-K filed June 17, 2005, File No. 1-8489); Form of Thirtieth Supplemental Indenture, dated July 1, 2005 (Exhibit 4.2, Form 8-K filed July 12, 2005, File No. 1-8489); Form of Thirty-First Supplemental Indenture, dated September 1, 2005 (Exhibit 4.2, Form 8-K filed September 26, 2005, File No. 1-8489); Forms of Thirty-Second and Thirty-Third Supplemental Indentures, dated November 1, 2006 (Exhibits 4.2 and 4.3, Form 8-K filed November 13, 2006, File No. 1-8489); Form of Thirty-Fourth Supplemental Indenture, dated November 1, 2007 (Exhibit 4.2, Form 8-K filed November 29, 2007, File No. 1-8489); Forms of Thirty-Fifth, Thirty-Sixth and Thirty-Seventh Supplemental Indentures, dated June 1, 2008 (Exhibits 4.2, 4.3 and 4.4, Form 8-K filed June 16, 2008, File No. 1-8489); Form of Thirty-Eighth Supplemental and Amending Indenture, dated November 1, 2008 (Exhibit 4.2, Form 8-K filed November 26, 2008, File No. 1-8489); Thirty-Ninth Supplemental Indenture Amending the Twenty-Seventh Supplemental Indenture, dated December 1, 2008 and effective as of December 16, 2008 (Exhibit 4.1, Form 8-K filed December 5, 2008, File No. 1-8489); Form of Thirty-Ninth Supplemental Indenture, dated August 1, 2009 (Exhibit 4.3, Form 8-K filed August 12, 2009, File No. 1-8489); Fortieth Supplemental Indenture, dated August 1, 2010 (Exhibit 4.3, Form 8-K filed September 2, 2010, File No. 1-8489).

4.9	Indenture, dated April 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.1, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated April 1, 2001 (Exhibit 4.2, Form 8-K filed April 12, 2001, File No. 1-3196); Forms of Second and Third Supplemental Indentures, dated October 25, 2001 (Exhibits 4.2 and 4.3, Form 8-K filed October 23, 2001, File No. 1-3196); Fourth Supplemental Indenture, dated May 1, 2002 (Exhibit 4.4, Form 8-K filed May 22, 2002, File No. 1-3196); Form of Fifth Supplemental Indenture, dated December 1, 2003 (Exhibit 4.2, Form 8-K filed November 25, 2003, File No. 1-3196); Form of Sixth Supplemental Indenture, dated November 1, 2004 (Exhibit 4.2, Form 8-K filed November 16, 2004, File No. 1-3196); Seventh Supplemental Indenture, dated June 27, 2007 (Exhibit 4.6, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.10	Form of Indenture for Junior Subordinated Debentures, dated October 1, 2001, between Consolidated Natural Gas Company and The Bank of New York Mellon (as successor trustee to Bank One Trust Company, National Association) (Exhibit 4.2, Form S-3 Registration Statement filed December 22, 2000, File No. 333-52602); Form of First Supplemental Indenture, dated October 23, 2001 (Exhibit 4.7, Form 8-K filed October 16, 2001, File No. 1-3196); Second Supplemental Indenture dated as of June 27, 2007 (Exhibit 4.8, Form 8-K filed July 3, 2007, File No. 1-8489).		X

4.11	Junior Subordinated Indenture II, dated June 1, 2006, between Dominion Resources, Inc. and The Bank of New York Mellon (successor to JPMorgan Chase Bank, N.A.), as Trustee (Exhibit 4.1, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); First Supplemental Indenture dated as of June 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489); Second Supplemental Indenture, dated as of September 1, 2006 (Exhibit 4.2, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489); Form of Third Supplemental and Amending Indenture, dated June 1, 2009 (Exhibit 4.2, Form 8-K filed June 15, 2009, File No. 1-8489).		X

4.12	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 23, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended June 30, 2006 filed August 3, 2006, File No. 1-8489).		X

4.13	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated September 29, 2006 (Exhibit 4.3, Form 10-Q for the quarter ended September 30, 2006 filed November 1, 2006, File No. 1-8489).		X


Exhibit Number	Description	Dominion		Virginia Power
4.14	Replacement Capital Covenant entered into by Dominion Resources, Inc. dated June 17, 2009 (Exhibit 4.3, Form 8-K filed June 15, 2009, File No. 1-8489).		X

10.1	DRI Services Agreement, dated January 28, 2000, by and between Dominion Resources, Inc., Dominion Resources Services, Inc. and Consolidated Natural Gas Service Company, Inc. (Exhibit 10(vii), Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-8489).		X

10.2	Services Agreement between Dominion Resources Services, Inc. and Virginia Electric and Power Company dated January 1, 2000 (Exhibit 10.19, Form 10-K for the fiscal year ended December 31, 1999 filed March 7, 2000, File No. 1-2255).		X		X

10.3	Agreement between PJM Interconnection, L.L.C. and Virginia Electric and Power Company (Exhibit 10.1, Form 8-K filed April 26, 2005, File No. 1-2255 and File No. 1-8489).		X		X

10.6	$3.0 billion Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., Barclays Capital, The Royal Bank of Scotland plc, and Wells Fargo Bank, N.A., as Syndication Agents, and other lenders named therein. (Exhibit 10.1, Form 8-K filed September 28, 2010, File No. 1-8489).		X		X

10.7	$500 million Three-Year Revolving Credit Agreement dated September 24, 2010 among Dominion Resources, Inc., Virginia Electric and Power Company, Keybank National Association, as Administrative Agent, Bayerische Landesbank, New York Branch, and U.S. Bank National Association, as Syndication Agents, and other lenders named therein. (Exhibit 10.2, Form 8-K filed September 28, 2010, File No. 1-8489).		X		X

10.8	Form of Settlement Agreement in the form of a proposed Consent Decree among the United States of America, on behalf of the United States Environmental Protection Agency, the State of New York, the State of New Jersey, the State of Connecticut, the Commonwealth of Virginia and the State of West Virginia and Virginia Electric and Power Company (Exhibit 10, Form 10-Q for the quarter ended March 31, 2003, File No. 1-8489).		X		X

10.10*	Dominion Resources, Inc. Executive Supplemental Retirement Plan, as amended and restated effective December 17, 2004 (Exhibit 10.5, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.11*	Dominion Resources, Inc. Incentive Compensation Plan, effective April 22, 1997, as amended and restated effective July 20, 2001 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489), as amended June 20, 2007 (Exhibit 10.9, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489 and Exhibit 10.5, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-2255).		X		X

10.12*	Form of Employment Continuity Agreement for certain officers of Dominion Resources, Inc. and Virginia Electric and Power Company, amended and restated July 15, 2003 (Exhibit 10.1, Form 10-Q for the quarter ended June 30, 2003 filed August 11, 2003, File No. 1-8489 and File No. 2255), as amended March 31, 2006 (Form 8-K filed April 4, 2006, File No. 1-8489).		X		X

10.13*	Dominion Resources, Inc. Retirement Benefit Restoration Plan, as amended and restated effective December 17, 2004 (Exhibit 10.6, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.14*	Dominion Resources, Inc. Executives’ Deferred Compensation Plan, amended and restated effective December 17, 2004 (Exhibit 10.7, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.15*	Dominion Resources, Inc. New Executive Supplemental Retirement Plan, effective January 1, 2005 (Exhibit 10.8, Form 8-K filed December 23, 2004, File No. 1-8489), amended January 19, 2006 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489), as amended December 1, 2006 and further amended January 1, 2007 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2006, filed February 28, 2007, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).		X		X

10.16*	Dominion Resources, Inc. New Retirement Benefit Restoration Plan, effective January 1, 2005 (Exhibit 10.9, Form 8-K filed December 23, 2004, File No. 1-8489), as amended January 1, 2007 (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File		X		X


Exhibit Number	Description	Dominion		Virginia Power
	No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255), as amended and restated effective January 1, 2009 (Exhibit 10.17, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489 and Exhibit 10.20, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-2255).

10.17*	Dominion Resources, Inc. Stock Accumulation Plan for Outside Directors, amended as of February 27, 2004 (Exhibit 10.15, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.1, Form 8-K filed December 23, 2004, File No. 1-8489).		X

10.18*	Dominion Resources, Inc. Directors Stock Compensation Plan, as amended February 27, 2004 (Exhibit 10.16, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.2, Form 8-K filed December 23, 2004, File No. 1-8489).		X

10.19*	Dominion Resources, Inc. Directors’ Deferred Cash Compensation Plan, as amended and in effect September 20, 2002 (Exhibit 10.4, Form 10-Q for the quarter ended September 30, 2002 filed November 8, 2002, File No. 1-8489) as amended effective December 31, 2004 (Exhibit 10.3, Form 8-K filed December 23, 2004, File No. 1-8489).		X

10.20*	Dominion Resources, Inc. Non-Employee Directors’ Compensation Plan, effective January 1, 2005, as amended and restated effective January 1, 2008 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489), as amended and restated effective January 1, 2009 (Exhibit 10.21, Form 10-K for the fiscal year ended December 31, 2008 filed February 26, 2009, File No. 1-8489), as amended and restated effective December 17, 2009 (Exhibit 10.18, Form 10-K filed for the fiscal year ended December 31, 2009 filed February 26, 2010, File No. 1-8489).		X

10.21*	Dominion Resources, Inc. Leadership Stock Option Plan, effective July 1, 2000, as amended and restated effective July 20, 2001 (Exhibit 10.2, Form 10-Q for the quarter ended June 30, 2001 filed August 3, 2001, File No. 1-8489 and File No. 1-2255).		X		X

10.22*	Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated February 18, 2011 (filed herewith).		X

10.23*	Dominion Resources, Inc. Security Option Plan, effective January 1, 2003, amended December 31, 2004 and restated effective January 1, 2005 (Exhibit 10.13, Form 8-K filed December 23, 2004, File No. 1-8489).		X		X

10.24*	Letter agreement between Dominion Resources, Inc. and Thomas F. Farrell II, dated February 27, 2003 (Exhibit 10.24, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended December 16, 2005 (Exhibit 10.1, Form 8-K filed December 16, 2005, File No. 1-8489).		X

10.25*	Employment agreement dated February 13, 2007 between Dominion Resources Services, Inc. and Mark F. McGettrick (Exhibit 10.34, Form 10-K for the fiscal year ended December 31, 2006 filed February 28, 2007, File No. 1-8489).		X

10.26*	Supplemental retirement agreement dated October 22, 2003 between Dominion Resources, Inc. and Paul D. Koonce (Exhibit 10.18, Form 10-K for the fiscal year ended December 31, 2003 filed March 1, 2004, File No. 1-2255).		X

10.27*	Supplemental Retirement Agreement dated December 12, 2000, between Dominion Resources, Inc. and David A. Christian (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2001 filed March 11, 2002, File No. 1-2255).		X

10.28*	Letter Agreement between Consolidated Natural Gas Company and George A. Davidson, Jr. dated December 22, 1998, related letter dated January 8, 1999 and Amendment to Letter Agreement dated February 26, 2008 (Exhibit 10.37, Form 10-K for the fiscal year ended December 31, 2007 filed February 28, 2008, File No. 1-8489).		X


Exhibit Number	Description	Dominion		Virginia Power
10.29*	Form of Restricted Stock Grant under 2006 Long-Term Compensation Program approved March 31, 2006 (Exhibit 10.1, Form 8-K filed April 4, 2006, File No. 1-8489).		X		X

10.30*	Form of Restricted Stock Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.1, Form 8-K filed April 5, 2007, File No. 1-8489).		X		X

10.31*	Form of Performance Grant under 2007 Long-Term Compensation Program approved March 30, 2007 (Exhibit 10.2, Form 8-K filed April 5, 2007, File No. 1-8489).		X		X

10.32*	Form of Restricted Stock Award Agreement under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.1, Form 8-K filed April 2, 2008, File No. 1-8489).		X		X

10.33*	2008 Performance Grant Plan under 2008 Long-Term Compensation Program approved March 27, 2008 (Exhibit 10.2, Form 8-K filed April 2, 2008, File No. 1-8489).		X		X

10.34*	Form of Advancement of Expenses for certain directors and officers of Dominion Resources, Inc., approved by the Dominion Resources, Inc. Board of Directors on October 24, 2008 (Exhibit 10.2, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489 and Exhibit 10.3, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-2255).		X		X

10.35*	2009 Performance Grant Plan under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.1, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X

10.36*	Form of Restricted Stock Award Agreement under 2009 Long-Term Compensation Program approved January 26, 2009 (Exhibit 10.2, Form 8-K filed January 29, 2009, File No. 1-8489).		X		X

10.37*	Dominion Resources, Inc. 2005 Incentive Compensation Plan, originally effective May 1, 2005, as amended and restated effective May 5, 2009 (Exhibit 10, Form 8-K filed May 11, 2009, File No. 1-8489), as amended December 17, 2010 (filed herewith).		X		X

10.38*	2010 Performance Grant Plan under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.1, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X

10.39*	Form of Restricted Stock Award Agreement under 2010 Long-Term Compensation Program approved January 21, 2010 (Exhibit 10.2, Form 8-K filed January 22, 2010, File No. 1-8489).		X		X

10.40*	Supplemental Retirement Agreement with Mark F. McGettrick effective May 19, 2010 (Exhibit 10.1, Form 8-K filed May 20, 2010, File No. 1-8489).		X		X
10.41*	2011 Performance Grant Plan under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.1, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X

10.42*	Form of Restricted Stock Award Agreement under 2011 Long-Term Compensation Program approved January 20, 2011 (Exhibit 10.2, Form 8-K filed January 21, 2011, File No. 1-8489).		X		X

10.43*	Restricted Stock Award Agreement for Thomas F. Farrell II, dated December 17, 2010 (Exhibit 10.1, Form 8-K filed December 17, 2010, File No. 1-8489).		X		X

10.44*	Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).		X

10.45*	Non-employee directors’ annual compensation for Dominion Resources, Inc. (filed herewith).		X

10.46*	Restricted Stock Award Agreement for Gary L. Sypolt approved September 24, 2010 (filed herewith).		X

12.a	Ratio of earnings to fixed charges for Dominion Resources, Inc. (filed herewith).		X

12.b	Ratio of earnings to fixed charges for Virginia Electric and Power Company (filed herewith).				X

12.c	Ratio of earnings to fixed charges and dividends for Virginia Electric and Power Company (filed herewith).				X

21	Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).		X		X

23	Consent of Deloitte & Touche LLP (filed herewith).		X		X

31.a	Certification by Chief Executive Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X

31.b	Certification by Chief Financial Officer of Dominion Resources, Inc. pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).		X


Exhibit Number	Description	Dominion		Virginia Power
31.c	Certification by Chief Executive Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).				X

31.d	Certification by Chief Financial Officer of Virginia Electric and Power Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (filed herewith).				X

32.a	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Dominion Resources, Inc. as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).		X

32.b	Certification to the Securities and Exchange Commission by Chief Executive Officer and Chief Financial Officer of Virginia Electric and Power Company as required by Section 906 of the Sarbanes-Oxley Act of 2002 (furnished herewith).				X

101^	The following financial statements from Dominion Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2010, filed on February 28, 2011, formatted in XBRL: (i) Consolidated Statements of Income, (ii) Consolidated Balance Sheets, (iii) Consolidated Statements of Common Shareholders’ Equity (iv) Consolidated Statements of Comprehensive Income (v) Consolidated Statements of Cash Flows, (vi) the Notes to Consolidated Financial Statements.		X

*	Indicates management contract or compensatory plan or arrangement


Commission File Number	Exact name of registrants as specified in their charters	I.R.S. Employer Identification Number

001-08489	DOMINION RESOURCES, INC.	54-1229715

001-02255	VIRGINIA ELECTRIC AND POWER COMPANY	54-0418825

	VIRGINIA (State or other jurisdiction of incorporation or organization)

	120 TREDEGAR STREET RICHMOND, VIRGINIA (Address of principal executive offices)	23219 (Zip Code)

	(804) 819-2000 (Registrants’ telephone number)


Title of Each Class		Name of Each Exchange on Which Registered
DOMINION RESOURCES, INC.
Common Stock, no par value		New York Stock Exchange
2009 Series A 8.375% Enhanced Junior Subordinated Notes		New York Stock Exchange

VIRGINIA ELECTRIC AND POWER COMPANY
Preferred Stock (cumulative), $100 par value, $5.00 dividend		New York Stock Exchange


Large accelerated filer x		Accelerated filer ¨		Non-accelerated filer ¨		Smaller reporting company ¨


Abbreviation or Acronym		Definition
Virginia Power		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
Virginia Settlement Approval Order		Order issued by the Virginia Commission in March 2010 concluding Virginia Power’s 2009 Base Rate Review
VPDES		Virginia Pollutant Discharge Elimination System
VPP		Volumetric production payment
VSWCB		Virginia State Water Control Board
West Virginia Commission		Public Service Commission of West Virginia


Name and Age		Business Experience Past Five Years⁽¹⁾
Thomas F. Farrell II (56)		Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date; Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors, President and CEO of CNG from January 2006 to June 2007; Director of Dominion from March 2005 to April 2007.

Mark F. McGettrick (53)		Executive Vice President and CFO of Dominion and Virginia Power from June 2009 to date; Executive Vice President of Dominion from April 2006 to May 2009; President and COO—Generation of Virginia Power from February 2006 to May 2009.

Paul D. Koonce (51)		Executive Vice President of Dominion from April 2006 to date; President and COO of Virginia Power from June 2009 to date; President and COO—Energy of Virginia Power from February 2006 to September 2007.

David A. Christian (56)		President and COO of Virginia Power from June 2009 to date; President and CNO of Virginia Power from October 2007 to May 2009; Senior Vice President—Nuclear Operations and CNO of Virginia Power from April 2000 to September 2007.

David A. Heacock (53)		President and CNO of Virginia Power from June 2009 to date; Senior Vice President of Dominion and President and COO—DVP of Virginia Power from June 2008 to May 2009; Senior Vice President—DVP of Virginia Power from October 2007 to May 2008; Senior Vice President—Fossil & Hydro of Virginia Power from April 2005 to September 2007.

Gary L. Sypolt (57)		President of DTI from June 2009 to date; President—Transmission of DTI from January 2003 to May 2009; President and COO—Transmission of Virginia Power from February 2006 to September 2007.

Robert M. Blue (43)		Senior Vice President—Law, Public Policy and Environment of Virginia Power, Dominion and DRS from January 2011 to date; Senior Vice President—Public Policy and Environment of Dominion and DRS from February 2010 to December 2010; Senior Vice President—Public Policy and Corporate Communications of Dominion and DRS from May 2008 to January 2010; Vice President—State and Federal Affairs of DRS from September 2006 to May 2008; Managing Director State Affairs and Corporate Policy of DRS from July 2005 to August 2006.

Steven A. Rogers (49)		Senior Vice President and Chief Administrative Officer of Dominion and President and Chief Administrative Officer of DRS from October 2007 to date; Senior Vice President and CAO of Dominion and Virginia Power from January 2007 to September 2007 and CNG from January 2007 to June 2007; Senior Vice President and Controller of Dominion and CNG from April 2006 to December 2006; Senior Vice President and Principal Accounting Officer of Virginia Power from April 2006 to December 2006; Vice President and Controller of Dominion and CNG and Vice President and Principal Accounting Officer of Virginia Power from June 2000 to April 2006.

Ashwini Sawhney (61)		Vice President—Accounting and Controller (CAO) of Dominion from May 2010 to date; Vice President and Controller (CAO) of Dominion from July 2009 to May 2010; Vice President—Accounting of Virginia Power from April 2006 to date; Vice President and Controller of Dominion from April 2007 to June 2009; Vice President—Accounting and Controller of Dominion from January 2007 to April 2007 and of CNG from January 2007 to June 2007; Vice President—Accounting of Dominion and CNG from April 2006 to December 2006; Assistant Corporate Controller of Dominion from June 2002 to April 2006; Assistant Corporate Controller of Virginia Power from January 1999 to April 2006.


Item Number		Page Number
	Glossary of Terms	1

Part I
1.	Business	5
1A.	Risk Factors	22
1B.	Unresolved Staff Comments	26
2.	Properties	26
3.	Legal Proceedings	29
4.	(Removed and reserved)	29
	Executive Officers of Dominion	30

Part II
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
6.	Selected Financial Data	32
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
7A.	Quantitative and Qualitative Disclosures About Market Risk	50
8.	Financial Statements and Supplementary Data	53
9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	124
9A.	Controls and Procedures	124
9B.	Other Information	127

Part III
10.	Directors, Executive Officers and Corporate Governance	127
11.	Executive Compensation	128
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	150
13.	Certain Relationships and Related Transactions, and Director Independence	150
14.	Principal Accountant Fees and Services	151

Part IV
15.	Exhibits and Financial Statement Schedules	152


Abbreviation or Acronym		Definition
2009 Base Rate Review		Order entered by the Virginia Commission in January 2009, pursuant to the Regulation Act, initiating reviews of the base rates and terms and conditions of all investor-owned utilities in Virginia
ABO		Accumulated benefit obligation
AOCI		Accumulated other comprehensive income (loss)
AFUDC		Allowance for funds used during construction
AIP		Annual Incentive Plan
AMR		Automated meter reading program deployed by East Ohio
Antero		Antero Resources
AROs		Asset retirement obligations
ASA		Primary metric used to measure customer service, Average Speed of Answer
ASLB		Atomic Safety and Licensing Board
bcf		Billion cubic feet
Bear Garden		A 580 MW intermediate combined cycle, natural gas-fired power station under construction in Buckingham County, Virginia
BP		BP Wind Energy North America Inc.
Brayton Point		Brayton Point power station
BREDL		Blue Ridge Environmental Defense League
BRP		Dominion Retirement Benefit Restoration Plan
BVP		Book Value Performance
CAA		Clean Air Act
CAIR		Clean Air Interstate Rule
CAMR		Clean Air Mercury Rule
CAO		Chief Accounting Officer
Carson-to-Suffolk line		Virginia Power project to construct an approximately 60-mile 500-kV transmission line in southeastern Virginia
CEO		Chief Executive Officer
CERCLA		Comprehensive Environmental Response, Compensation and Liability Act of 1980
CD&A		Compensation Discussion and Analysis
CDEP		Connecticut Department of Environmental Protection
CDO		Collateralized debt obligation
CFTC		Commodity Futures Trading Commission
CFO		Chief Financial Officer
CGN Committee		Compensation, Governance and Nominating Committee
CNG		Consolidated Natural Gas Company
CNO		Chief Nuclear Officer
CO₂		Carbon dioxide
COL		Combined Construction Permit and Operating License
Companies		Dominion and Virginia Power, collectively
CONSOL		CONSOL Energy, Inc.
COO		Chief Operating Officer
Cove Point		Dominion Cove Point LNG, LP
CWA		Clean Water Act
Dallastown		Dallastown Realty
DCI		Dominion Capital, Inc.
DD&A		Depreciation, depletion and amortization expense
DEI		Dominion Energy, Inc.
Dodd-Frank Act		The Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010
DOE		Department of Energy
Dominion		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
Dominion Direct^®		A dividend reinvestment and open enrollment direct stock purchase plan
DPP		Dominion Pension Plan
Dresden		Partially-completed merchant generation facility sold in 2007
DRS		Dominion Resources Services, Inc.
DSM		Demand-side management
DTI		Dominion Transmission, Inc.
DVP		Dominion Virginia Power operating segment
E&P		Exploration & production
East Ohio		The East Ohio Gas Company, doing business as Dominion East Ohio
ECCP		Energy Conservation Council of Pennsylvania


Abbreviation or Acronym		Definition
EPA		Environmental Protection Agency
EPACT		Energy Policy Act of 2005
EPS		Earnings per share
ERISA		The Employment Retirement Income Security Act of 1974
ERO		Electric Reliability Organization
ESRP		Dominion Executive Supplemental Retirement Plan
Fairless		Fairless power station
FASB		Financial Accounting Standards Board
FERC		Federal Energy Regulatory Commission
Fitch		Fitch Ratings Ltd.
Fowler Ridge		A wind-turbine facility joint venture with BP in Benton County, Indiana
FTRs		Financial transmission rights
GAAP		U.S. generally accepted accounting principles
GHG		Greenhouse gas
GWSA		Global Warming Solutions Act
HAP		Hazardous air pollutant
Hayes-to-Yorktown line		Virginia Power project to construct an approximately eight-mile 230-kV transmission line in southeastern Virginia
Hope		Hope Gas, Inc., doing business as Dominion Hope
HVAC		Heating, ventilating and air conditioning
IOGA		Independent Oil and Gas Association of West Virginia, Inc.
IRS		Internal Revenue Service
ISO		Independent system operator
ISO-NE		ISO New England
Joint Committee		U.S. Congressional Joint Committee on Taxation
June 2006 hybrids		2006 Series A Enhanced Junior Subordinated Notes due 2066
June 2009 hybrids		2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to extensions no later than 2079
Kewaunee		Kewaunee nuclear power station
Kincaid		Kincaid power station
kV		Kilovolt
LIBOR		London Interbank Offered Rate
LIFO		Last-in-first-out inventory method
LNG		Liquefied natural gas
LTIP		Long-term incentive program
MACT		Maximum Achievable Control Technology
Manchester Street		Manchester Street power station
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDE		Maryland Department of the Environment
Meadow Brook-to-Loudoun line		Project to construct an approximately 270-mile 500-kV transmission line that begins in southwestern Pennsylvania, crosses West Virginia, and terminates in northern Virginia, of which Virginia Power will construct approximately 65 miles in Virginia and Trans-Allegheny Interstate Line Company will construct the remainder
Medicare Act		The Medicare Prescription Drug, Improvement and Modernization Act of 2003
Medicare Part D		Prescription drug benefit introduced in the Medicare Act
MISO		Midwest Independent Transmission System Operators, Inc.
Millstone		Millstone nuclear power station
MNES		Mitsubishi Nuclear Energy Systems, Inc., a wholly-owned subsidiary of Mitsubishi Heavy Industries, Inc.
Moody’s		Moody’s Investors Service
Mt. Storm-to-Doubs line		Virginia Power project to rebuild approximately 96 miles of an existing 500-kV transmission line in Virginia and West Virginia
MW		Megawatt
MWh		Megawatt hour
NAV		Net asset value
NAAQS		National Ambient Air Quality Standards
NCEMC		North Carolina Electric Membership Corporation
NedPower		A wind-turbine facility joint venture with Shell in Grant County, West Virginia
NEIL		Nuclear Electric Insurance Limited
NEOs		Named executive officers
NERC		North American Electric Reliability Corporation
NGLs		Natural gas liquids
NO₂		Nitrogen dioxide


Abbreviation or Acronym		Definition
Non-Employee Directors Plan		Non-Employee Directors Compensation Plan
North Anna		North Anna nuclear power station
North Carolina Commission		North Carolina Utilities Commission
North Carolina Settlement Approval Order		Order issued by the North Carolina Commission in December 2010 approving the Stipulation and Settlement Agreement filed by Virginia Power in connection with the ending of its North Carolina base rate moratorium
NO_X		Nitrogen oxide
NPDES		National Pollutant Discharge Elimination System
NRC		Nuclear Regulatory Commission
NYMEX		New York Mercantile Exchange
NYSE		New York Stock Exchange
ODEC		Old Dominion Electric Cooperative
Ohio Commission		Public Utilities Commission of Ohio
OSHA		Occupational Safety and Health Administration
Peaker facilities		Collectively, the three natural gas-fired merchant generation peaking facilities sold in March 2007
Pennsylvania Commission		Pennsylvania Public Utility Commission
Peoples		The Peoples Natural Gas Company
PIPP		Percentage of Income Payment Plan
PIR		Pipeline Infrastructure Replacement program deployed by East Ohio
PJM		PJM Interconnection, LLC
PM&P		Pearl Meyer & Partners
PNG Companies LLC		An indirect subsidiary of Babcock & Brown Infrastructure Fund North America
RCCs		Replacement Capital Covenants
RCRA		Resource Conservation and Recovery Act
Regulation Act		Legislation effective July 1, 2007, that amended the Virginia Electric Utility Restructuring Act and fuel factor statute, which legislation is also known as the Virginia Electric Utility Regulation Act
REIT		Real estate investment trust
RGGI		Regional Greenhouse Gas Initiative
Riders C1 and C2		Rate adjustment clauses associated with the recovery of costs related to certain DSM programs
Rider R		A rate adjustment clause associated with the recovery of costs related to Bear Garden
Rider S		A rate adjustment clause associated with the recovery of costs related to the Virginia City Hybrid Energy Center
Rider T		A rate adjustment associated with the recovery of certain electric transmission-related expenditures
ROE		Return on equity
ROIC		Return on invested capital
RPM Buyers		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
RPS		Renewable Portfolio Standard
RTEP		Regional transmission expansion plan
RTO		Regional transmission organization
SAIDI		Metric used to measure electric service reliability, System Average Interruption Duration Index
Salem Harbor		Salem Harbor power station
SEC		Securities and Exchange Commission
SELC		Southern Environmental Law Center
September 2006 hybrids		2006 Series B Enhanced Junior Subordinated Notes due 2066
Shell		Shell WindEnergy, Inc.
SO₂		Sulfur dioxide
Standard & Poor’s		Standard & Poor’s Ratings Services, a division of the McGraw-Hill Companies, Inc.
State Line		State Line power station
Surry		Surry nuclear power station
TGP		Tennessee Gas Pipeline Company
TSR		Total shareholder return
UEX Rider		Uncollectible Expense Rider
U.S.		United States of America
US-APWR		Mitsubishi Heavy Industry’s Advanced Pressurized Water Reactor
VEBA		Voluntary Employees’ Beneficiary Association
VIE		Variable interest entity
Virginia City Hybrid Energy Center		A 585 MW (nominal) baseload carbon-capture compatible, clean coal powered electric generation facility under construction in Wise County, Virginia
Virginia Commission		Virginia State Corporation Commission


	Page No.
*Dominion Resources, Inc.*
Report of Independent Registered Public Accounting Firm		54
Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008		55
Consolidated Balance Sheets at December 31, 2010 and 2009		56
Consolidated Statements of Common Shareholders’ Equity at December 31, 2010, 2009 and 2008 and for the years then ended		58
Consolidated Statements of Comprehensive Income at December 31, 2010, 2009 and 2008 and for the years then ended		59
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		60

*Virginia Electric and Power Company*
Report of Independent Registered Public Accounting Firm		61
Consolidated Statements of Income for the years ended December 31, 2010, 2009 and 2008		63
Consolidated Balance Sheets at December 31, 2010 and 2009		64
Consolidated Statements of Common Shareholder’s Equity at December 31, 2010, 2009 and 2008 and for the years then ended		66
Consolidated Statements of Comprehensive Income at December 31, 2010, 2009 and 2008 and for the years then ended		67
Consolidated Statements of Cash Flows for the years ended December 31, 2010, 2009 and 2008		68

Combined Notes to Consolidated Financial Statements		69


	Common Stock						Dominion Shareholders
	Shares			Amount			Other Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling interest			Total
(millions)

Balance at December 31, 2007		577		$	5,733		$	175	$	3,510		$	(12	)	$	29		$	9,435
Net income including noncontrolling interests										1,851						(1	)		1,850
Issuance of stock—employee and direct stock purchase plans		4			196														196
Stock awards and stock options exercised (net of change in unearned compensation)		2			65														65
Tax benefit from stock awards and stock options exercised		—						7											7
Cumulative effect of change in accounting principle⁽¹⁾										(2	)								(2	)
Deconsolidation of noncontrolling interest																(28	)		(28	)
Dividends⁽²⁾										(1,189	)⁽³⁾								(1,189	)
Other comprehensive loss, net of tax													(257	)					(257	)
Balance at December 31, 2008		583			5,994			182		4,170			(269	)		—			10,077
Net income including noncontrolling interests										1,304									1,304
Issuance of stock—employee and direct stock purchase plans		6			212														212
Stock awards and stock options exercised (net of change in unearned compensation)		2			70														70
Other stock issuances⁽⁴⁾		8			249														249
Tax benefit from stock awards and stock options exercised								3											3
Cumulative effect of change in accounting principle⁽¹⁾										12			(12	)					—
Dividends⁽²⁾										(800	)								(800	)
Other comprehensive income, net of tax													70						70
Balance at December 31, 2009		599			6,525			185		4,686			(211	)		—			11,185
Net income including noncontrolling interests										2,825									2,825
Issuance of stock—employee and direct stock purchase plans		1			10														10
Stock awards and stock options exercised (net of change in unearned compensation)		2			80														80
Stock repurchases		(21	)		(900	)													(900	)
Tax benefit from stock awards and stock options exercised								9											9
Dividends⁽²⁾										(1,093	)								(1,093	)
Other comprehensive loss, net of tax													(119	)					(119	)
Balance at December 31, 2010		581		$	5,715		$	194	$	6,418		$	(330	)		—		$	11,997


Derivatives in cash flow hedging relationships Year Ended December 31, 2010	Amount of Gain (Loss) Recognized in AOCI on Derivatives (Effective Portion)⁽¹⁾			Amount of Gain (Loss) Reclassified from AOCI to Income			Increase (Decrease) in Derivatives Subject to Regulatory Treatment⁽²⁾
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Electric fuel and other energy-related purchases				$	(1	)
Purchased electric capacity					4
Total commodity	$	(1	)		3		$	(17	)
Interest rate⁽³⁾		(1	)		9			(27	)
Foreign currency⁽⁴⁾		—			—			(2	)
Total	$	(2	)	$	12		$	(46	)
Year Ended December 31, 2009
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Electric fuel and other energy-related purchases				$	(8	)
Purchased electric capacity					5
Total commodity	$	(3	)		(3	)	$	6
Interest rate⁽³⁾		15			—			87
Foreign currency⁽⁴⁾		—			1			(3	)
Total	$	12		$	(2	)	$	90


Derivatives not designated as hedging instruments	Amount of Gain (Loss) Recognized in Income on Derivatives⁽¹⁾
Year Ended December 31,	2010			2009
(millions)
Derivative Type and Location of Gains (Losses)
Commodity⁽²⁾		$51			$(165	)
Interest rate⁽³⁾		(3	)		—
Total		$48			$(165	)


	Bath County Pumped Storage Station⁽¹⁾			North Anna Power Station⁽¹⁾			Clover Power Station⁽¹⁾			Millstone Unit 3⁽²⁾
(millions, except percentages)
Ownership interest		60.0	%		88.4	%		50.0	%		93.5	%
Plant in service	$	1,022		$	2,294		$	562		$	1,001
Accumulated depreciation		(474	)		(1,047	)		(178	)		(212	)
Nuclear fuel		—			491			—			302
Accumulated amortization of nuclear fuel		—			(366	)		—			(206	)
Plant under construction		1			246			8			56


	Dominion Generation			Dominion Energy			DVP		Corporate and Other			Total
(millions)
Balance at December 31, 2008⁽¹⁾	$	1,455		$	861		$	1,091	$	96		$	3,503
Reallocation due to segment realignment		—			15			—		(15	)		—
Business acquisition adjustment		(117	)		(30	)		—		(2	)		(149	)
Balance at December 31, 2009⁽¹⁾	$	1,338		$	846		$	1,091	$	79		$	3,354
Business disposition adjustment		—			(134	)		—		(79	)		(213	)
Balance at December 31, 2010⁽¹⁾	$	1,338		$	712		$	1,091	$	—		$	3,141


At December 31,	2010 Weighted- average Coupon⁽¹⁾			2010			2009
(millions, except percentages)
Virginia Electric and Power Company⁽²⁾:
Unsecured Senior Notes:
4.5% to 5.25%, due 2010 to 2015		5.01	%	$	1,200		$	1,430
3.45% to 8.875%, due 2016 to 2038		6.12	%		4,694			4,408
Tax-Exempt Financings:⁽³⁾
Variable rates, due 2016 to 2041		1.25	%		219			119
7.65%, due 2010					—			1
1.375% to 6.5%, due 2017 to 2040		4.25	%		608			503
Virginia Electric and Power Company total principal				$	6,721		$	6,461
Securities due within one year⁽⁴⁾		7.74	%		(15	)		(245	)
Unamortized discount and premium, net					(4	)		(3	)
Virginia Electric and Power Company total long-term debt				$	6,702		$	6,213
Dominion Resources, Inc.:
Unsecured Senior Notes:
2.25% to 8.125%, due 2010 to 2015		5.14	%	$	1,901		$	2,029
5.2% to 8.875%, due 2016 to 2038⁽⁵⁾		6.34	%		4,193			4,193
Variable rate, due 2010					—			300
Unsecured Convertible Senior Notes, 2.125%, due 2023⁽⁶⁾					202			202
Unsecured Junior Subordinated Notes Payable to Affiliated Trusts, 7.83% and 8.4%, due 2027 and 2031		7.85	%		268			268
Enhanced Junior Subordinated Notes, 6.3% to 8.375%, due 2064 and 2066		7.51	%		1,469			1,485
Unsecured Debentures and Senior Notes⁽⁷⁾:
5.0% to 6.85%, due 2010 to 2014		5.58	%		1,091			1,291
6.8% and 6.875%, due 2026 and 2027		6.81	%		89			89
Dominion Energy, Inc.⁽⁸⁾:
Secured Senior Note, 7.33%, due 2020⁽⁹⁾					171			183
Tax-Exempt Financings, 5.0% and 5.75%, due 2033 to 2042		5.30	%		124			124
Virginia Electric and Power Company total principal (from above)					6,721			6,461
Dominion Resources, Inc. total principal				$	16,229		$	16,625
Fair value hedge valuation⁽¹⁰⁾					49			23
Securities due within one year⁽¹¹⁾		6.35	%		(497	)		(1,137	)
Unamortized discount and premium, net					(23	)		(30	)
Dominion Resources, Inc. total long-term debt				$	15,758		$	15,481


	Fair Value Measurements
	Pension Plans
At December 31,	2010								2009
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	1	$	264	$	—	$	265	$	—	$	233	$	—	$	233
U.S. equity:
Large Cap		937		197		—		1,134		886		114		—		1,000
Other		436		96		—		532		243		—		—		243
Non-U.S. equity:
Large Cap		231		—		—		231		242		111		—		353
Other		119		365		—		484		20		36		—		56
Fixed income:
Corporate debt instruments		32		694		—		726		57		611		—		668
U.S. Treasury securities and agency debentures		168		216		—		384		8		188		—		196
State and municipal		2		42		—		44		101		11		—		112
Other securities		—		3		—		3		—		1		—		1
Real estate:
REITs		51		—		—		51		33		—		—		33
Partnerships		—		—		271		271		—		—		344		344
Other alternative investments:
Private equity		—		—		400		400		—		—		344		344
Debt		—		—		262		262		—		—		241		241
Hedge funds		—		—		345		345		—		—		388		388
Total⁽¹⁾	$	1,977	$	1,877	$	1,278	$	5,132	$	1,590	$	1,305	$	1,317	$	4,212


	Fair Value Measurements
	Other Postretirement Plans
At December 31,	2010								2009
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(millions)
Cash equivalents	$	—	$	13	$	—	$	13	$	—	$	13	$	—	$	13
U.S. equity:
Large Cap		43		293		—		336		291		35		—		326
Other		20		41		—		61		12		—		—		12
Non-U.S. equity:
Large Cap		87		—		—		87		85		5		—		90
Other		5		17		—		22		1		2		—		3
Fixed income:
Corporate debt instruments		1		106		—		107		3		120		—		123
U.S. Treasury securities and agency debentures		8		248		—		256		—		183		—		183
State and municipal		—		8		—		8		5		25		—		30
Real estate:
REITs		2		—		—		2		2		—		—		2
Partnerships		—		—		22		22		—		—		26		26
Other alternative investments:
Private equity		—		—		61		61		—		—		54		54
Debt		—		—		40		40		—		—		36		36
Hedge funds		—		—		17		17		—		—		19		19
Total⁽¹⁾	$	166	$	726	$	140	$	1,032	$	399	$	383	$	135	$	917


	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Pension Plans
	2010														2009
	Real Estate			Private Equity		Debt			Hedge Funds			Total			Real Estate			Private Equity			Debt		Hedge Funds		Total
(millions)
Balance at January 1,	$	344		$	344	$	241		$	388		$	1,317		$	438		$	267		$	191	$	324	$	1,220
Actual return on plan assets:
Relating to assets still held at the reporting date		8			56		27			27			118			(91	)		128			19		—		56
Relating to assets sold during the period		—			—		—			—			—			(1	)		1			—		—		—
Purchases, sales and settlements		(81	)		—		(6	)		(70	)		(157	)		(2	)		(52	)		31		64		41
Balance at December 31	$	271		$	400	$	262		$	345		$	1,278		$	344		$	344		$	241	$	388	$	1,317


Year Ended December 31,	DVP		Dominion Generation		Corporate and Other			Adjustments & Eliminations			Consolidated Total
(millions)
2010
Operating revenue	$	1,680	$	5,546	$	(7	)	$	—		$	7,219
Depreciation and amortization		344		327		—			—			671
Interest income		11		4		—			—			15
Interest and related charges		158		189		—			—			347
Income taxes		228		385		(71	)		—			542
Net income (loss)		377		630		(155	)		—			852
Capital expenditures		1,035		1,199		—			—			2,234
Total assets (billions)		9.9		13.8		—			(1.4	)		22.3
2009
Operating revenue	$	1,465	$	5,560	$	(441	)	$	—		$	6,584
Depreciation and amortization		320		320		1			—			641
Interest income		11		6		—			—			17
Interest and related charges		158		191		—			—			349
Income taxes		183		241		(277	)		—			147
Net income (loss)		313		475		(432	)		—			356
Capital expenditures		839		1,649		—			—			2,488
Total assets (billions)		9.0		12.3		—			(1.2	)		20.1
2008
Operating revenue	$	1,439	$	5,478	$	17		$	—		$	6,934
Depreciation and amortization		310		298		—			—			608
Interest income		15		9		—			(3	)		21
Interest and related charges		144		167		1			(3	)		309
Income taxes		182		331		(13	)		—			500
Net income (loss)		307		583		(26	)		—			864
Capital expenditures		792		1,245		—			—			2,037


Name and Age	Principal Occupation and Directorships in Public Corporations for Last Five Years⁽¹⁾	Year First Elected as Director
Thomas F. Farrell II (56)	Chairman of the Board of Directors and CEO of Virginia Power from February 2006 to date; Chairman of the Board of Directors of Dominion from April 2007 to date; President and CEO of Dominion from January 2006 to date; Chairman of the Board of Directors, President and CEO of CNG from January 2006 to June 2007; Director of Dominion from March 2005 to April 2007. Mr. Farrell has served as a director of Altria Group, Inc. since 2008. Mr. Farrell’s qualifications to serve as a director include his 15 years of industry experience as well as his legal expertise, having served as General Counsel for Dominion and Virginia Power and as a practicing attorney with a private firm. He is a member of the boards of the Institute of Nuclear Power Operations and Edison Electric Institute through which he actively represents the interests of Dominion, Virginia Power and the energy sector. Mr. Farrell also has extensive community and public interest involvement and serves or has served on the boards of many non-profit and university foundations.	1999
Mark F. McGettrick (53)	Executive Vice President and CFO of Virginia Power and Dominion from June 2009 to date; President and COO—Generation of Virginia Power from February 2006 to May 2009; Executive Vice President of Dominion from April 2006 to May 2009. Mr. McGettrick’s qualifications to serve as a director include his more than 30 years of power generation management and industry experience. He currently serves on the George Mason University board of visitors and business council and is on the board of directors of the Dominion Foundation. Mr. McGettrick also has community and public interest involvement and serves or has served on many non-profit foundations and boards.	2009
Steven A. Rogers (49)	Senior Vice President and Chief Administrative Officer of Dominion and President and Chief Administrative Officer of DRS from October 2007 to date; Senior Vice President and CAO of Virginia Power and Dominion from January 2007 to September 2007 and CNG from January 2007 to June 2007; Senior Vice President and Controller of Dominion and CNG from April 2006 to December 2006; Senior Vice President and Principal Accounting Officer of Virginia Power from April 2006 to December 2006; Vice President and Principal Accounting Officer of Virginia Power and Vice President and Controller of Dominion and CNG from June 2000 to April 2006. Mr. Rogers’ qualifications to serve as a director include his 15 years of industry experience, prior work with Deloitte & Touche, LLP and his former membership in the FASB’s Financial Accounting Standards Advisory Committee. Mr. Rogers also has community and public interest involvement and serves or has served on many non-profit foundations and boards.	2007


Pay Element	Primary Objectives	Key Features & Behavioral Focus
Base Salary	Ÿ Provide competitive level of fixed cash compensation for performing day-to-day responsibilities Ÿ Attract and retain talent	Ÿ Generally targeted at or slightly above peer median, with individual and company-wide considerations Ÿ Rewards individual performance and level of experience
Annual Incentive Plan	Ÿ Provide competitive level of at-risk cash compensation for achievement of short-term financial and operational goals Ÿ Align short-term compensation with Dominion’s annual budget, earnings goals, business plans and core values	Ÿ Cash payments based on achievement of annual financial and individual operating and stewardship goals Ÿ Rewards achievement of annual financial goals for Dominion and business unit and individual goals selected to support longer-term strategies
Long-Term Incentive Program	Ÿ Provide competitive level of at-risk compensation for achievement of long-term performance goals Ÿ Create long-term shareholder value Ÿ Retain talent and support the succession planning process	Ÿ A combination of performance-based cash and restricted stock awards (for 2010, a 50/50 mix) Ÿ Encourages and rewards officers for making decisions and investments that create long-term shareholder value as reflected in superior relative total shareholder returns, as well as achieving desired returns on invested capital
Employee and Executive Benefits	Ÿ Provide competitive retirement and other benefit programs that attract and retain highly qualified individuals Ÿ Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management	Ÿ Includes benefit programs, executive retirement plans, limited perquisites, and change in control and other agreements, supplemented with non-compete provisions in the non-qualified retirement plans Ÿ Encourages officers to remain with Dominion long-term and to act in the best interest of shareholders, even during any potential change in control


Name and Principal Position	Year		Salary⁽¹⁾		Stock Awards⁽²⁾		Non-Equity Incentive Plan Compensation⁽³⁾		Change in Pension Value and Nonqualified Deferred Compensation Earnings⁽⁴⁾		All Other Compensation⁽⁵⁾		Total
Thomas F. Farrell II Chairman and Chief Executive Officer		2010	$	342,720	$	2,164,671	$	1,634,640	$	551,838	$	44,950	$	4,738,819
		2009		348,000		870,001		1,604,280		461,615		188,429		3,472,325
		2008		452,833		1,140,010		2,559,300		997,551		238,040		5,387,734
Mark F. McGettrick Executive Vice President and Chief Financial Officer		2010		305,402		413,970		841,435		1,590,831		33,281		3,184,919
		2009		298,195		345,010		766,034		861,244		83,450		2,353,933
		2008		327,253		390,014		1,061,894		376,799		87,288		2,243,248
Paul D. Koonce Executive Vice President and COO—DVP		2010		431,679		478,139		998,467		642,025		40,721		2,591,031
Paul D. Koonce Executive Vice President and COO—DVP		2009		242,983		220,508		533,418		188,154		58,545		1,243,608
David A. Christian President and COO— Generation		2010		299,384		225,247		554,103		661,527		49,013		1,789,274
		2009		259,229		152,752		434,621		588,777		67,838		1,503,217
		2008		263,498		159,252		517,672		299,988		64,877		1,305,287
James F. Stutts Senior Vice President & General Counsel		2010		184,212		178,497		327,583		117,069		57,295		864,656


Name	Stock Awards
Name	Number of Shares or Units of Stock That Have Not Vested (#)			Market Value of Shares or Units of Stock That Have Not Vested⁽¹⁾ ($)
Thomas F. Farrell II		20,568	⁽²⁾	$	878,665
		23,877	⁽³⁾		1,020,025
		26,161	⁽⁴⁾		1,117,598
		28,000	⁽⁵⁾		1,196,160
Mark F. McGettrick		8,447	⁽²⁾		360,856
		9,806	⁽³⁾		418,912
		11,051	⁽⁴⁾		472,099
Paul D. Koonce		9,366	⁽²⁾		400,116
		10,873	⁽³⁾		464,495
		12,764	⁽⁴⁾		545,278
David A. Christian		4,217	⁽²⁾		180,150
		4,896	⁽³⁾		209,157
		6,013	⁽⁴⁾		256,875
James F. Stutts⁽⁶⁾		2,571	⁽²⁾		109,833
		2,984	⁽³⁾		127,476
		4,765	⁽⁴⁾		203,561


Name	Number of Shares Acquired on Vesting (#)		Value Realized on Vesting ($)
Thomas F. Farrell II		18,773	$	785,275
Mark F. McGettrick		7,710		322,509
Paul D. Koonce		8,549		357,605
David A. Christian		3,849		161,004
James F. Stutts		9,304		362,468


Name	Plan Name	Number of Years Credited Service⁽¹⁾		Present Value of Accumulated Benefit⁽²⁾
Thomas F. Farrell II	Pension Plan		15.00	$	164,027
	Benefit Restoration Plan		26.00		1,983,467
	Supplemental Retirement Plan		26.00		3,291,133
Mark F. McGettrick	Pension Plan		26.50		406,415
	Benefit Restoration Plan		30.00		2,244,665
	Supplemental Retirement Plan		30.00		2,284,161
Paul D. Koonce	Pension Plan		12.00		305,759
	Benefit Restoration Plan		12.00		453,179
	Supplemental Retirement Plan		12.00		2,133,063
David A. Christian	Pension Plan		26.50		572,903
	Benefit Restoration Plan		26.50		1,250,127
	Supplemental Retirement Plan		26.50		1,717,741
James F. Stutts⁽³⁾	Pension Plan		12.75		230,285
	Benefit Restoration Plan		21.00		587,375
	Supplemental Retirement Plan		21.00		728,642


DOMINION RESOURCES, INC.

By:		/S/ THOMAS F. FARRELL II
		(Thomas F. Farrell II, Chairman, President and Chief Executive Officer)