DOMINION RESOURCES INC /VA/
Item 1. Business
GENERAL
Dominion, headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Dominion’s strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. Dominion’s portfolio of assets includes approximately 27,500 MW of generation, 6,000 miles of electric transmission lines, 56,000 miles of electric distribution lines in Virginia and North Carolina, 12,000 miles of natural gas transmission, gathering and storage pipeline, 21,700 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less, and 1.3 Tcfe of proved natural gas and oil reserves. Dominion also owns the nation’s largest underground natural gas storage system, operates approximately 942 bcf of storage capacity and serves retail energy customers in twelve states.
Dominion is focused on expanding its investment in regulated electric generation, and regulated electric and natural gas transmission infrastructure within and around its existing footprint. As a result, regulated capital projects will continue to receive priority treatment in its spending plans. Dominion expects this will increase its earnings contribution from regulated operations, while reducing the sensitivity of its earnings to commodity prices. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and natural gas and oil exploration and production in the Appalachian basin of the U.S. Dominion’s operations are conducted through various subsidiaries, including Virginia Power.
Virginia Power, headquartered in Richmond, Virginia and incorporated in Virginia in 1909 as a Virginia public service corporation, is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. In Virginia, Virginia Power conducts business under the name “Dominion Virginia Power.” In North Carolina, it conducts business under the name “Dominion North Carolina Power” and serves retail customers located in the northeastern region of the state, excluding certain municipalities. In addition, Virginia Power sells electricity at wholesale prices to rural electric cooperatives, municipalities and into wholesale electricity markets. All of Virginia Power’s common stock is owned by Dominion.
The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power) or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.
The term “Virginia Power” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
EMPLOYEES
As of December 31, 2009, Dominion had approximately 17,900 full-time employees, of which approximately 6,600 employees are subject to collective bargaining agreements. As of December 31, 2009, Virginia Power had approximately 7,400 full-time employees, of which approximately 3,300 employees are subject to collective bargaining agreements.
PRINCIPAL EXECUTIVE OFFICES
Dominion and Virginia Power’s principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and their telephone number is (804) 819-2000.
WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINION AND VIRGINIA POWER
Dominion and Virginia Power file their annual, quarterly and current reports, proxy statements and other information with the SEC. Their SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov. You may also read and copy any document they file at the SEC’s public reference room at 100 F Street, N.E., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.
Dominion and Virginia Power make their SEC filings available, free of charge, including the annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports, through Dominion’s internet website www.dom.com, as soon as practicable after filing or furnishing the material to the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning Dominion at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000. Information contained on Dominion’s website is not incorporated by reference in this report.
ACQUISITIONS AND DISPOSITIONS
Following are significant acquisitions and divestitures by Dominion and Virginia Power during the last five years.
ACQUISITION OF KEWAUNEE NUCLEAR POWER STATION
In July 2005, Dominion completed the acquisition of Kewaunee, a 556 MW facility in northeastern Wisconsin for approximately $192 million in cash. The operations of Kewaunee are included in the Dominion Generation operating segment.
ACQUISITION OF USGEN NEW ENGLAND, INC. POWER STATIONS
In January 2005, Dominion completed the acquisition of three fossil-fuel fired generation facilities for $642 million in cash. The facilities include Brayton Point, a 1,551 MW facility in Somerset, Massachusetts; Salem Harbor, a 754 MW facility in Salem, Massachusetts; and Manchester Street, a 432 MW facility in Providence, Rhode Island. The operations of these facilities are included in the Dominion Generation operating segment.
ASSIGNMENT OF MARCELLUS ACREAGE
In 2008, Dominion completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage.
SALE OF E&P PROPERTIES
In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion. See Note 4 to the Consolidated Financial Statement for additional information.
In 2006, Dominion received approximately $393 million of proceeds from sales of certain gas and oil properties, primarily resulting from the sale of certain properties located in Texas and New Mexico.
The historical results of these operations are included in the Corporate and Other segment.
SALE OF MERCHANT FACILITIES
In March 2007, Dominion sold three Peaker facilities for net cash proceeds of $254 million. The Peaker facilities included the 625 MW Armstrong facility in Shelocta, Pennsylvania; the 600 MW Troy facility in Luckey, Ohio; and the 313 MW Pleasants facility in St. Mary’s, West Virginia. Following the decision to sell these assets in December 2006, the results of these operations were reclassified to discontinued operations and are presented in the Corporate and Other segment.
SALE OF DRESDEN
In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million.
SALE OF CERTAIN DCI OPERATIONS
In August 2007, Dominion completed the sale of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC) and Dallastown for approximately $30 million.
In March 2008, Dominion reached an agreement to sell its remaining interest in the subordinated notes of a third-party CDO entity held as an investment by DCI and in April 2008 received proceeds of $54 million, including accrued interest. As discussed in Note 25 to the Consolidated Financial Statements, Dominion deconsolidated the CDO entity as of March 31, 2008.
TRANSFER OF VIRGINIA POWER ENERGY MARKETING, INC. TO DOMINION
On December 31, 2005, Virginia Power completed a transfer of its indirect wholly-owned subsidiary, VPEM, to Dominion through a series of dividend distributions, in exchange for a capital contribution of $633 million. VPEM provides fuel, gas supply management and price risk management services to other Dominion affiliates and engages in energy trading and marketing activities. As a result of the transfer, VPEM’s results of operations were reclassified to discontinued operations in Virginia Power’s Consolidated Statements of Income and presented in its Corporate and Other segment.
SALE OF PEOPLES
In March 2006, Dominion entered into an agreement with Equitable to sell two of its wholly-owned regulated gas distribution subsidiaries, Peoples and Hope. Peoples serves approximately 358,000 customer accounts in Pennsylvania and Hope serves approximately 114,000 customer accounts in West Virginia. This sale was subject to regulatory approvals in the states in which the companies operate, as well as antitrust clearance under the HSR Act. In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. Dominion continued to seek other offers for the purchase of these utilities.
In July 2008, Dominion entered into an agreement with an indirect subsidiary of BBIFNA to sell Peoples and Hope. In May 2009, following a change in ownership of the general partner of BBIFNA and other related transactions, BBIFNA was renamed “SteelRiver Infrastructure Fund North America LP”. The sale of Peoples and Hope to the SteelRiver Buyer, an indirect subsidiary of the SteelRiver Fund, was expected to close in 2009, subject to state regulatory approvals in Pennsylvania and West Virginia. In November 2009, the Pennsylvania Commission approved the settlement entered into among Dominion, Peoples, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding, thereby approving the sale of Peoples to the SteelRiver Buyer. In December 2009, the West Virginia Commission denied the application for the sale of Hope. Dominion decided to retain Hope, but continue with the sale of Peoples. The sales price for Peoples was approximately $780 million, subject to changes in working capital, capital expenditures and affiliated borrowings. In February 2010, Dominion completed the sale of Peoples and netted after-tax proceeds of approximately $542 million. A more detailed description of the sale can be found in Note 4 to the Consolidated Financial Statements.
OPERATING SEGMENTS
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. Dominion also reports a Corporate and Other segment that includes its corporate, service company and other functions and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4 to the Consolidated Financial Statements. Corporate and Other also includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. Prior to the fourth quarter of 2009, Hope was included in Dominion’s Corporate and Other segment and its assets and liabilities were classified as held for sale. During the fourth quarter of 2009, following Dominion’s decision to retain this subsidiary, Hope was transferred to the Dominion Energy operating segment and its assets and liabilities were reclassified from held for sale.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
While daily operations are managed through the operating segments previously discussed, assets remain wholly-owned by Dominion and Virginia Power and their respective legal subsidiaries.
A description of the operations included in the Companies’ primary operating segments is as follows:
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
X
LNG import and storage
X
Appalachian gas exploration and production
X
Producer services
X
For additional financial information on business segments, including revenues from external customers, see Notes 1 and 27 to the Consolidated Financial Statements. For additional information on operating revenue related to Dominion’s and Virginia Power’s principal products and services, see Notes 2 and 5 to the Consolidated Financial Statements.
DVP
The DVP Operating Segment of Virginia Power includes Virginia Power’s regulated electric transmission and distribution (including customer service) operations. Virginia Power’s electric transmission and distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.
Revenue provided by electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Changes in revenue are driven primarily by weather, customer growth and other factors impacting consumption such as the economy and energy conservation. Variability in earnings results from changes in rates, weather, the economy, customer growth and operating and maintenance expenditures. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As a result, electric service reliability has improved. The metric used to measure electric service reliability (System Average Interruption Duration Index, excluding major storm events) has improved from 139 minutes at the end of 2004 to 110 minutes at the end of 2009. Customer service options are also being enhanced and expanded through the use of technology. Customers now have the ability to use the Internet for routine billing and payment transactions, connecting and disconnecting service, reporting outages and obtaining outage updates. At the end of 2009, over 800,000 of Virginia Power’s customers were signed up to manage their account on-line through dom.com, and over 2.9 million transactions were performed on-line in 2009. This reflects a transaction increase of 45% over 2008. As electric distribution continues to evolve, safety, operational performance and customer service will remain as key focal areas.
The Virginia General Assembly enacted legislation in April 2007 that instituted a modified cost-of-service rate model for the Virginia jurisdiction of Virginia Power’s utility operations, subject to base rate caps in effect through December 31, 2008. In 2009, the Virginia Commission initiated a review of Virginia Power’s base rates. A discussion of Virginia Power’s proposal in the case, including a settlement agreement to which it is a party, is contained in Electric Regulation in Virginia under Regulation.
Revenue provided by Virginia Power’s electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from changes in rates and the timing of property additions, retirements and depreciation.
In April 2008, FERC granted an application by Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4% on the common equity base of these operations, effective as of January 1, 2008. The FERC ruling did not materially impact the Company’s results of operations; however, the FERC-approved formula method allows Virginia Power to earn a more current return on its growing investment in electric transmission infrastructure. In addition, in August 2008, FERC granted an application by Virginia Power’s electric transmission operations requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects and approved an incentive of 1.5% for four of the projects and an incentive of 1.25% for the other seven. See Federal Regulations in Regulation for additional information.
Virginia Power is a member of PJM, an RTO, and its electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to NERC by EPACT, Virginia Power’s electric transmission operations are
committed to meeting NERC standards, modernizing their infrastructure and maintaining superior system reliability. Virginia Power’s electric transmission operations will continue to focus on safety, operational performance and execution of PJM’s RTEP.
The DVP Operating Segment of Dominion includes all of Virginia Power’s regulated electric transmission and distribution operations as discussed above, as well as Dominion’s nonregulated retail energy marketing operations.
Dominion’s retail energy marketing operations compete in nonregulated energy markets and have experienced strong customer growth during the past few years. The retail business requires limited capital investment and currently employs fewer than 150 people. The retail customer base is diversified across three product lines-natural gas, electricity and home warranty services. In natural gas, Dominion has a heavy concentration of customers in markets where utilities have a long-standing commitment to customer choice. In electricity, Dominion pursues markets where utilities have divested of generation assets and where customers are permitted and have opted to purchase from the market. Major growth drivers are customer additions, new markets/products and sales channels, and supply optimization.
COMPETITION
DVP Operating Segment-Dominion and Virginia Power
Within Virginia Power’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since its electric transmission facilities are integrated into PJM, electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. Virginia Power is seeing continued growth in new customers in its transmission and distribution operations.
DVP Operating Segment-Dominion
Dominion’s retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas and electricity. Customers in these markets have the right to select a retail marketer and typically do so based upon price savings or price stability; however, incumbent utilities have the advantage of long-standing relationships with their customers and greater name recognition in their markets.
REGULATION
Virginia Power’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission. Virginia Power’s electric transmission rates, tariffs and terms of service are subject to regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation for additional information.
PROPERTIES
Virginia Power has approximately 6,000 miles of electric transmission lines of 69 kV or more located in the states of North Carolina, Virginia and West Virginia. Portions of Virginia Pow -
er’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, any surplus capacity that may exist in these lines. While Virginia Power owns and maintains its electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance, and exchange of capacity and energy for such facilities.
Each year, as part of PJM’s RTEP process, reliability projects are authorized. In June 2006, PJM authorized construction of numerous electric transmission upgrades through 2011. Virginia Power is involved in two of the major construction projects, which are designed to improve the reliability of service to customers and the region, and are subject to applicable state and federal permits and approvals.
In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route proposed for the line which is adjacent to, or within, existing transmission line right-of-ways. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In March 2009, the Sierra Club filed an appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the Supreme Court of West Virginia in April 2009. An appeal of the Pennsylvania Commission’s approval by the Energy Conservation Council of Pennsylvania is pending. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. In November 2009, the Virginia Supreme Court affirmed the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and, subject to the receipt of all regulatory approvals, is expected to be completed in June 2011.
In October 2008, the Virginia Commission authorized the construction of the Carson-to-Suffolk line. This project is estimated to cost $224 million and is expected to be completed in June 2011. The siting and construction of these transmission lines are subject to applicable state and federal permits and approvals.
In addition, Virginia Power’s electric distribution network includes approximately 56,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The grants for most of its electric lines contain right-of-ways that have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where right-of-ways have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.
SOURCES OF ENERGY SUPPLY
DVP Operating Segment-Dominion and Virginia Power
DVP’s supply of electricity to serve Virginia Power customers is produced or procured by Dominion Generation. See Dominion Generation for additional information.
DVP Operating Segment-Dominion
The supply of electricity to serve Dominion’s retail energy marketing customers is procured through market wholesalers and RTO or ISO transactions and its supply of gas to serve its customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.
SEASONALITY
DVP Operating Segment-Dominion and Virginia Power
DVP’s earnings vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days for DVP’s electric utility related operations does not produce the same increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
DVP Operating Segment-Dominion
The earnings of Dominion’s retail energy marketing operations also vary seasonally. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs, while the demand for gas peaks during the winter months to meet heating needs.
Dominion Generation
The Dominion Generation Operating Segment of Virginia Power includes the generation operations of the Virginia Power regulated electric utility and its related energy supply operations. Virginia Power’s utility generation operations primarily serve the supply requirements for the DVP segment’s utility customers. The generation mix is diversified and includes coal, nuclear, gas, oil and renewables. The generation facilities of Virginia Power’s electric utility fleet are located in Virginia, West Virginia and North Carolina. As discussed in Properties, Virginia Power has plans to add additional generation capacity to satisfy future growth in its utility service area.
Earnings for the Generation operating segment of Virginia Power primarily result from the sale of electricity generated by its utility fleet. Due to 1999 Virginia deregulation legislation, as amended in 2004 and 2007, revenues for serving Virginia jurisdictional retail load were based on capped rates through 2008. Additionally, fuel costs for the utility fleet, including purchased power, were subject to fixed-rate recovery provisions until July 1, 2007. Pursuant to the 2007 amendments to the fuel cost recovery statute, annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, were re-instituted beginning July 1, 2007 for Virginia jurisdictional customers. The Virginia General Assembly enacted legislation in April 2007 that returned the Virginia jurisdiction of Virginia Power’s generation operations to a modified cost-of-service rate model, subject to base rate caps in effect through December 31, 2008. As a result, Virginia Power reapplied accounting guidance for cost-based regulation to those operations in April 2007, when the legislation was enacted. In 2009, the Virginia Commission initiated a review of Virginia Power’s base rates. A discussion of
Virginia Power’s proposal in the case, including a settlement agreement to which it is a party, is contained in Electric Regulation in Virginia under Regulation. Variability in earnings for Virginia Power’s generation operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages.
The Dominion Generation Operating Segment of Dominion includes Virginia Power’s generation facilities and its related energy supply operations described above as well as the generation operations of Dominion’s merchant fleet and energy marketing and price risk management activities for these assets. The generation facilities of Dominion’s merchant fleet are located in Connecticut, Illinois, Indiana, Massachusetts, Pennsylvania, Rhode Island, West Virginia and Wisconsin. In the merchant generation business, Dominion is adding generation capacity through several new renewable energy projects and uprates, as discussed in Properties. The Generation operating segment of Dominion derives its earnings primarily from the sale of electricity generated by Virginia Power’s utility and Dominion’s merchant generation assets, as well as associated capacity from Dominion’s merchant generation assets.
Variability in earnings provided by Dominion’s merchant fleet relates to changes in market-based prices received for electricity and capacity. Market-based prices for electricity are largely dependent on commodity prices and the demand for electricity, which is primarily dependent upon weather. Capacity prices are dependent upon resource requirements in relation to the supply available (both existing and new) in the forward capacity auctions, which are held approximately three years in advance of the associated delivery year. Dominion manages electric and capacity price volatility by hedging a substantial portion of its expected near-term sales with derivative instruments and also entering into long-term power sales agreements, which should help mitigate the adverse impact on earnings from declines in commodity prices, such as those experienced during 2008 and 2009. Variability also results from changes in the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.
COMPETITION
Dominion Generation Operating Segment-Dominion and Virginia Power
Retail choice was made available to Virginia Power’s Virginia jurisdictional electric utility customers beginning January 1, 2003; however, no significant competition developed. In April 2007, the Virginia General Assembly passed legislation ending retail choice for most of these customers effective January 1, 2009. See Regulation-State Regulations-Electric for more information. Currently, North Carolina does not offer retail choice to electric customers.
Dominion Generation Operating Segment-Dominion
Dominion Generation’s merchant generation fleet owns and operates several facilities in the Midwest that operate within functioning RTOs. A significant portion of the output from these facilities is sold under long-term contracts, with expiration dates ranging from December 31, 2012 to August 31, 2017, and is therefore largely unaffected by competition.
Dominion Generation’s other merchant assets also operate within functioning RTOs and primarily compete on the basis of price. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units have a variety of short and medium-term contracts, and also compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, Dominion applies its expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to similar assets within the region.
REGULATION
Virginia Power’s utility generation fleet and Dominion’s merchant generation fleet are subject to regulation by FERC, the NRC, the EPA, the DOE, the Army Corps of Engineers and other federal, state and local authorities. Virginia Power’s utility generation fleet is also subject to regulation by the Virginia Commission and the North Carolina Commission. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
For a listing of Dominion’s and Virginia Power’s generation facilities, see Item 2. Properties.
Dominion Generation Operating Segment-Dominion and Virginia Power
Based on available generation capacity and current estimates of growth in customer demand in Virginia Power’s utility service area, it will need additional generation capacity over the next ten years. Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in its core market in Virginia. As part of this program, the following projects have recently been completed or are in various stages of development:
In June 2008, Virginia Power commenced the operation of two additional natural gas-fired electric generating units (Units 3 and 4) totaling 321 MW at its Ladysmith power station to supply electricity during periods of peak demand. In addition, in April 2009, a fifth combustion turbine (Unit 5) with 160 MW of capacity commenced operations.
The Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the Virginia City Hybrid Energy Center located in Wise County, Virginia, which once operational, will generate about 585 MW. In July 2008, the SELC, on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia. In April 2009, the Virginia Supreme Court affirmed the Virginia Commission’s Final Order. In its Final Order, the Virginia Commission approved an initial return on common equity for the facility of 12.12%, consisting of a base return of 11.12% plus a 100 basis point enhancement that Virginia law provides for new conventional coal generation facili -
ties. The Virginia Commission also authorized Virginia Power to apply for an additional 100 basis point enhancement upon a demonstration that the plant is carbon-capture compatible. The enhanced return will apply to the Virginia City Hybrid Energy Center during construction and through the first twelve years of the facility’s service life.
In June 2008, the Virginia State Air Pollution Control Board approved and issued an air permit to construct and operate the Virginia City Hybrid Energy Center and also approved and issued another air permit for hazardous emissions. Construction of the Virginia City Hybrid Energy Center commenced and the facility is expected to be in operation by 2012. In August 2008, the SELC, on behalf of four environmental groups, filed Petitions for Appeal in Richmond Circuit Court challenging the approval of both of the air permits. The Richmond Circuit Court issued an Order in September 2009 upholding the initial air permit and upholding the second air permit for hazardous emissions except for one condition related to the permit limit for mercury emissions. The hazardous emissions air permit was amended by the Virginia Department of Environmental Quality in September 2009 to comply with the Richmond Circuit Court Order. The permit amendment does not impact the project. In October 2009, the SELC filed a Notice of Appeal of the court’s Order regarding the initial air permit with the Richmond Circuit Court, initiating the appeals process to the Virginia Court of Appeals. The SELC’s opening brief to the Virginia Court of Appeals was filed in January 2010. Briefing should conclude in February 2010. Oral argument will be scheduled upon the completion of briefing. A decision by the Court of Appeals is expected by the second or third quarter of 2010. The result of the appeal does not impact the project’s construction.
Virginia Power is considering the construction of a third nuclear unit at a site located at North Anna, which Virginia Power owns along with ODEC. Virginia Power and ODEC have obtained an Early Site Permit for the North Anna site from the NRC. In November 2007, Virginia Power, along with ODEC, filed an application with the NRC for a COL that references a specific reactor design and which would allow Virginia Power to build and operate a new nuclear unit at North Anna. In January 2008, the NRC accepted Virginia Power’s application for the COL and deemed it complete. In December 2008, Virginia Power terminated a long-lead agreement with its vendor with respect to the reactor design identified in its COL application and certain related equipment. A competitive process was initiated in 2009 to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to Virginia Power. If, as a result of this process, Virginia Power chooses a different reactor design, it will amend its COL application, as necessary. Virginia Power has not yet committed to building a new nuclear unit.
The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the Atomic Safety and Licensing Board of the NRC granted a request for a hearing on one of eight contentions filed by the Blue Ridge Environmental Defense League. In August 2009, the Atomic Safety and Licensing Board dismissed this contention as moot, but in November 2009 admitted a new contention filed by Blue Ridge Environmental Defense League. Virginia Power filed a motion for reconsideration of this ruling that is pending before the Atomic Safety and Licensing
Board. Absent additional contentions, the mandatory NRC hearing will be uncontested with respect to other issues. Virginia Power has a cooperative agreement with the DOE to share equally the cost of developing a COL that references a specific reactor technology; however, this agreement may not remain in effect going forward if Virginia Power chooses a different reactor technology.
In June 2008, the DOE issued a solicitation announcement inviting the submission of applications for loan guarantees from the DOE under its Loan Guarantee Program in support of debt financing for nuclear power facility projects in the U.S. In May 2009, the DOE announced the names of four energy companies that were selected to begin negotiations for federal loan guarantees for proposed new nuclear units in the U.S. Although Virginia Power, in a two-part process, submitted an application for a federal loan guarantee for the proposed North Anna unit, the Company was not among those selected. While Virginia Power can provide no assurance, because of the dynamic nature of the market for new nuclear units, there may be other opportunities to secure a loan guarantee with the DOE.
In March 2008, Virginia Power purchased the Bear Garden power station development project which, once constructed, will generate about 580 MW. The air and water permits for the combined-cycle, natural gas-fired power station have been amended to allow for Virginia Power’s project designs and schedules. Authorization was granted by the Virginia Commission in March 2009 to build the proposed combined-cycle, natural gas-fired power station and transmission interconnection line for an estimated $619 million, excluding financing costs. A gas pipeline is scheduled to be constructed by Columbia Gas of Virginia to provide gas supply to the power station.
In March 2008, Virginia Power also purchased a power station development project in Warren County, Virginia for future development. If developed, the project will involve the construction of a combined-cycle, natural gas-fired power station expected to generate more than 600 MW of electricity and will be subject to necessary regulatory approvals.
In April 2008, Virginia Power announced a joint effort with BP to evaluate wind energy projects, which, if completed, would increase the renewable energy capacity of Virginia Power’s utility generation fleet.
Dominion Generation Operating Segment-Dominion
In addition to the Powering Virginia projects, Dominion has invested in several wind farm projects. In December 2006, Dominion acquired a 50% interest in NedPower. NedPower consists of two phases totaling 264 MW. The first (164 MW) and second (100 MW) phases began commercial operations in July and December 2008, respectively.
In January 2008, Dominion acquired a 50% interest in Fowler Ridge. The first phase consisting of 300 MW achieved full commercial operations in March 2009. Dominion has a long-term agreement with Fowler Ridge to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, Dominion reached an agreement with BP to split the development assets of the final 350 MW phase. Under
the agreement, Dominion will own 150 MW of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.
In April 2008, Dominion announced plans to develop Prairie Fork. Construction of this wind turbine facility is subject to receipt of all necessary permits and approvals.
In 2008 and 2009, Dominion completed two uprates totaling 120 MW at Fairless. Additionally, in January 2009, Dominion successfully implemented an NRC-approved 7% uprate at Unit 3 of Millstone. This increased the unit’s output by approximately 77 MW from 1,150 MW to 1,227 MW, or enough to power an additional 60,000 homes.
SOURCES OF ENERGY SUPPLY
Dominion Generation Operating Segment-Dominion and Virginia Power
Dominion Generation uses a variety of fuels to power its electric generation and purchases power for utility system load requirements and to satisfy physical forward sale requirements, as described below. Some of these agreements have fixed commitments and are included as contractual obligations in Future Cash Payments for Contractual Obligations and Planned Capital Expenditures in Item 7. MD&A.
Nuclear Fuel-Dominion Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.
Fossil Fuel-Dominion Generation primarily utilizes coal, oil and natural gas in its fossil fuel plants. Dominion Generation’s coal supply is obtained through long-term contracts and short-term spot agreements from both domestic and international suppliers.
Dominion Generation’s natural gas and oil supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from underground storage fields owned by Dominion or third parties.
Dominion Generation manages a portfolio of natural gas transportation contracts (capacity) that allows flexibility in delivering natural gas to its gas turbine fleet, while minimizing costs.
Purchased Power-Dominion Generation purchases electricity from the PJM spot market and through power purchase agreements with other suppliers to provide for utility system load requirements.
Dominion Generation also occasionally purchases electricity from the PJM, ISO-NE and MISO spot markets to satisfy physical forward sale requirements as part of its merchant generation operations.
Dominion Generation Operating Segment-Virginia Power
Presented below is a summary of Virginia Power’s actual system output by energy source:
(1) Excludes ODEC’s 50% ownership interest in the Clover Power Station. The average cost of coal for 2009 Virginia in-system generation was $33.58 per MWh.
(2) Excludes ODEC’s 11.6% ownership interest in North Anna.
SEASONALITY
Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. An increase in heating degree-days for Virginia Power’s utility operations does not produce the same increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.
NUCLEAR DECOMMISSIONING
Dominion Generation Operating Segment-Dominion and Virginia Power
Virginia Power has a total of four licensed, operating nuclear reactors at its Surry and North Anna power stations in Virginia.
Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers and placed into trusts have been invested to fund the expected future costs of decommissioning the Surry and North Anna units.
Virginia Power believes that the decommissioning funds and their expected earnings for the Surry and North Anna units will be sufficient to cover expected decommissioning costs, particularly when combined with future ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. This reflects the long-term investment horizon, since the units will not be decommissioned for decades, and a positive long-term outlook for trust fund investment returns. Virginia Power will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.
The total estimated cost to decommission Virginia Power’s four nuclear units is $2.2 billion in 2009 dollars and is primarily based upon site-specific studies completed in 2009. The current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Virginia Power expects to decommission the Surry and North Anna units during the period 2032 to 2067.
Dominion Generation Operating Segment-Dominion
In addition to the four nuclear units discussed above, Dominion has three licensed, operating nuclear reactors, two at Millstone in Connecticut and one at Kewaunee in Wisconsin. A third Millstone unit ceased operations before Dominion acquired the power station. As part of Dominion’s acquisition of both Millstone and Kewaunee, it acquired decommissioning funds for the related units. Dominion believes that the amounts currently available in the decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units. Dominion will continue to monitor these trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC. The total estimated cost to decommission Dominion’s eight units is $4.5 billion in 2009 dollars and is primarily based upon site-specific studies completed in 2009. For the Millstone and Kewaunee operating units, the current cost estimate assumes decommissioning activities will begin shortly after cessation of operations, which will occur when the operating licenses expire. Millstone Unit 1 is not in service and selected minor decommissioning activities are being performed. This unit will continue to be monitored until full decommissioning activities begin for the remaining Millstone operating units. Dominion expects to start minor decommissioning activities at Millstone Unit 2 in 2035, with full decommissioning of Millstone Units 1, 2 and 3 during the period 2045 to 2069. In August 2008, Dominion filed an application with the NRC to renew the Kewaunee operating license. A renewal would permit Kewaunee to operate through December 21, 2033 with full decommissioning of Kewaunee during the period 2033 to 2065. The NRC docketed the application in October 2008. No requests for a hearing were received on the application, although there will be opportunities for public input as the NRC conducts its review of the application. The NRC’s schedule contemplates completion of the uncontested proceeding in February 2011.
The estimated decommissioning costs and license expiration dates for the nuclear units owned by Dominion and Virginia Power are shown in the following table.
(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 Nuclear Connecticut and a 6.53% undivided interest in Unit 3 is owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation. Amounts reflect 100% of the decommissioning cost for Millstone Unit 3.
(4) Kewaunee Unit 1 original license expiration year is 2013. The cost estimate is based on the license renewal expiration year of 2033.
Dominion Energy
Dominion Energy includes Dominion’s Ohio and West Virginia regulated natural gas distribution companies, regulated gas transmission pipeline and storage operations, natural gas gathering and by-products extraction activities, regulated LNG operations and Appalachian E&P operations. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.
The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in Dominion’s gas transmission pipeline and storage business is its gas gathering and extraction activity, which sells extracted products at market rates. Revenue provided by Dominion’s regulated gas transmission and storage, and LNG operations is based primarily on rates established by FERC. Dominion’s gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio and West Virginia. Revenue provided by its gas distribution operations is based primarily on rates established by the Ohio and West Virginia Commissions. The profitability of these businesses is dependent on Dominion’s ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from operating and maintenance expenditures, as well as changes in rates and the demand for services, which can be dependent on weather, changes in commodity prices and the economy.
Revenue from gas transportation, gas storage, and LNG storage and regasification services are largely based on firm, fee-based contractual arrangements.
In October 2008, Dominion East Ohio implemented a rate case settlement which began a transition to a Straight Fixed Variable rate design. Under this rate design, Dominion East Ohio recovers a larger portion of its fixed operating costs through a flat monthly charge accompanied by a reduced volumetric base delivery rate. Accordingly, Dominion East Ohio’s revenue is less impacted by weather-related fluctuations in natural gas consumption than under the traditional rate design.
Dominion’s Appalachian E&P business generates income from the sale of natural gas and oil it produces from its reserves, including fixed-term overriding royalty interests formerly associated with its VPP agreements (VPP royalty interests) discussed in Note 11 to the Consolidated Financial Statements. Variability in earnings relates to changes in commodity prices, which are largely market-based, production volumes, which are impacted by numerous factors including drilling success and timing of development projects, and drilling costs which may be impacted
by drilling rig availability and other external factors. Production from VPP royalty interests declined significantly due to the expiration of these interests in February 2009. Dominion manages commodity price volatility by hedging a substantial portion of its near-term expected production, which should help mitigate the adverse impact on earnings from declines in gas and oil prices, such as those experienced in 2008 and 2009. These hedging activities may require cash deposits to satisfy collateral requirements. Dominion’s Appalachian E&P business added 138 bcfe to its gas and oil reserves as a result of its drilling program during 2009, as compared to production of 50 bcfe in 2009, excluding production from VPP royalty interests.
Earnings from Dominion Energy’s other nonregulated business, producer services, are subject to variability associated with changes in commodity prices. Producer services uses physical and financial arrangements to hedge this price risk.
COMPETITION
Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. Dominion also competes with gas marketers seeking to provide or arrange transportation, storage and other services. Alternative energy sources, such as oil or coal, provide another level of competition. Although competition is based primarily on price, the array of services that can be provided to customers is also an important factor. The combination of capacity rights held on certain long-line pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enable Dominion to tailor its services to meet the needs of individual customers.
Retail competition for gas supply exists to varying degrees in the two states in which Dominion’s gas distribution subsidiaries operate. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion has offered an Energy Choice program to customers, in cooperation with the Ohio Commission. West Virginia does not require customer choice in its retail natural gas markets at this time. See Regulation-State Regulations-Gas for additional information.
REGULATION
Dominion Energy’s natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion Energy’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio and West Virginia Commissions. See State Regulations and Federal Regulations in Regulation for more information.
PROPERTIES
Dominion Energy’s gas distribution network is located in the states of Ohio and West Virginia. This network involves approximately 21,700 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owner of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.
Dominion Energy has approximately 12,000 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 349,000 acres of operated leaseholds.
The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 942 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by Dominion’s partners totals about 242 bcf. Dominion Energy also has about 15 bcf of above-ground storage capacity at its Cove Point LNG facility. Dominion Energy has about 134 compressor stations with more than 747,000 installed compressor horsepower.
Dominion Energy also owns about 1.3 Tcfe of proved natural gas and oil reserves and produces approximately 137 million cubic feet equivalent of natural gas and oil per day from its leasehold acreage and facility investments in Appalachia.
In 2006, FERC approved the proposed expansion of Dominion’s Cove Point terminal and DTI pipeline and the commencement of construction of the project. The expansion project included the installation of two new LNG storage tanks at Dominion’s Cove Point terminal, each capable of storing 160,000 cubic meters of LNG, pumps, gas-turbine generators, and vaporization capacity to increase the terminal send-out by 800,000 dekatherms per day. Dominion installed 48 miles of 36-inch pipeline to increase the terminal take-away capacity to approximately 1,800,000 dekatherms per day. In addition, Dominion’s DTI gas pipeline and storage system was expanded by building approximately 120 miles of pipeline, two new compressor stations in Pennsylvania and other upgrades to other compressor stations in West Virginia and New York. The DTI facilities associated with the Cove Point expansion project were placed into service in December 2008, the Cove Point LNG terminal expansion was placed into service in January 2009 and the remainder of the expanded Cove Point facilities were placed into commercial service in March 2009.
In September 2008, Dominion completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. Dominion received proceeds of approximately $347 million. Under the agreement, Dominion receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage. Following this transaction, Dominion controls drilling rights on approximately 450,000 acres in the Marcellus Shale formation. Dominion plans to monetize its remaining acreage within the next two years in order to reduce or eliminate its equity financing needs.
DTI has announced the proposed development of a gas pipeline project, known as the Appalachian Gateway Project, which is designed to transport gas on a firm basis out of the Appalachian Basin in West Virginia and southwestern Pennsylvania to DTI’s interconnect with Texas Eastern Transmission Corporation at Oakford, Pennsylvania. An open season for the project concluded in September 2008. The project is fully subscribed under long
term binding agreements. The Appalachian Gateway Project is expected to be fully placed into service by the fall of 2012.
Dominion has announced the Gathering Enhancement Project, a $253 million expansion of its natural gas gathering, processing and liquids facilities in West Virginia. The project is designed to increase the efficiency and reduce high pressures in its gathering system, thus increasing the amount of natural gas local producers can move through Dominion’s West Virginia system. Construction started in 2009 and will be completed by the fourth quarter of 2012. The cost of the project will be paid for by rates charged to producers.
Dominion has also announced the proposed development of the Keystone Connector Project, a joint venture with The Williams Companies that would transport new natural gas supplies from the Appalachian Basin to Transcontinental Gas Pipe Line Corporation’s Station 195, providing access to markets throughout the eastern U.S. Dominion is currently in discussions regarding the continued development of the Keystone Connector Project. Project timing is subject to producer drilling plans in the Appalachian Basin, as well as customer demand throughout the mid-Atlantic and Northeast regions.
SOURCES OF ENERGY SUPPLY
Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major interstate gas pipelines, including the Rockies Express East pipeline and large markets in the Northeast and mid-Atlantic regions. Dominion’s pipelines are part of an interconnected gas transmission system, which provides access to supplies nationwide for local distribution companies, marketers, power generators and industrial and commercial customers.
Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Northeast, mid-Atlantic and Midwest regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transmission capacity. Dominion Energy’s natural gas supply is obtained from various sources including Dominion’s own production, less royalties, purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers.
SEASONALITY
Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March, however implementation of the Straight Fixed Variable rate design at Dominion East Ohio has reduced the earnings impact of weather-related fluctuations. Demand for services at Dominion’s pipelines and storage business can also be weather sensitive. Dominion Energy’s Appalachian E&P business can be impacted by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for Dominion’s unhedged natural gas and oil production, can be impacted by seasonal weather changes, the effects of weather on operations and the economy. Dominion’s producer services business is affected by seasonal changes in the prices of
commodities that it transports, stores and actively markets and trades.
Corporate and Other
Corporate and Other Segment-Virginia Power
Virginia Power’s Corporate and Other segment primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
Corporate and Other Segment-Dominion
Dominion’s Corporate and Other segment includes its corporate, service company and other functions (including unallocated debt) and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4 to the Consolidated Financial Statements. Operations disposed of during 2007 included all of Dominion’s non-Appalachian E&P operations, three natural gas-fired merchant generation peaker facilities and certain DCI operations. Operations disposed of during 2008 included certain DCI operations. Operations to be disposed of at December 31, 2009 include Peoples, which Dominion sold in February 2010. In addition, Corporate and Other includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.
ENVIRONMENTAL STRATEGY
Dominion and Virginia Power are committed to being good environmental stewards. Their ongoing objective is to provide reliable, affordable energy for their customers while being environmentally responsible. The integrated strategy to meet this objective consists of five major elements:

Conservation and load management;

Renewable generation development;

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

Improvements in other energy infrastructure; and

Compliance with applicable environmental laws, regulations and rules.
Conservation plays a role in meeting the growing demand for electricity. Virginia re-regulation legislation enacted in 2007 provides incentives for energy conservation and sets a goal to reduce electricity consumption by retail customers in 2022 by ten percent of the amount consumed in 2006 through the implementation of conservation programs. A description of Virginia Power’s conservation and load management programs is detailed below.
Dominion and Virginia Power are working to improve their own energy efficiency, both in using less fuel to produce the same amount of energy and to use less energy in their operations. Recent uprates of their facilities have resulted in significant increases in generation capacity and lower emissions to meet the needs of their customers.
Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have
passed legislation setting targets for renewable power. Virginia Power is committed to meeting Virginia’s goals of 12% renewable power by 2022 and 15% by 2025 and North Carolina’s renewable portfolio standard of 12.5% by 2021. In July 2009, Virginia Power applied to the Virginia Commission for approval to participate in Virginia’s renewable energy portfolio standard program. The application identifies a Renewable Portfolio Standard Plan for meeting Virginia’s goals and includes a combination of existing renewable energy sources, development of new renewable energy facilities and purchase of renewable energy certificates. Virginia Power also anticipates using at least 10% biomass (woodwaste) at the Virginia City Hybrid Energy Center.
In addition, Dominion is a 50% owner of the NedPower wind energy facility in Grant County, West Virginia. Dominion’s share of this project produces 132 MW of renewable energy. Dominion has also acquired a 50% interest in a joint venture with BP to develop the Fowler Ridge wind-turbine facility in Benton County, Indiana. The first phase with a generating capacity of 300 MW reached full commercial operations in March 2009. Dominion has a long-term agreement with the joint venture to purchase 200 MW of energy, capacity and environmental attributes from this first phase. In June 2009, Dominion reached an agreement with BP to split the development assets of the final 350 MW phase. Under the agreement with BP, Dominion will own 150 MW of the development assets and BP will retain the remaining development assets. Closing of this transaction was effective in December 2009.
Virginia Power has announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in the core market of Virginia. Virginia Power expects that these investments collectively will provide the following benefits: expanded electricity production capability; increased technological and fuel diversity; and a reduction in the CO2 emission intensity of its generation fleet. A critical aspect of the Powering Virginia program is the extent to which Virginia Power seeks to reduce the carbon intensity of its generation fleet by developing generation facilities with zero CO2 and low CO2 emissions, as well as economically viable facilities that can be equipped for CO2 capture and storage. There is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store GHG emissions. There are six generally recognized GHGs including CO2, methane, nitrous oxide, sulfur hexafluoride, hydrofluorocarbons, and perfluorocarbons. Given that new generation units have useful lives of up to 55 years, Virginia Power will give full consideration to CO2 and other GHG emissions when making long-term decisions. See Dominion Generation-Properties for more information.
Virginia Power plans to make a significant investment in improving the capabilities and reliability of its electric transmission and distribution system. These enhancements are primarily aimed at meeting Virginia Power’s continued goal of providing reliable service. An additional benefit will be added capacity to efficiently deliver electricity from the renewable projects now being developed or to be developed in the future. See Global Climate Change under Regulations for more information.
In further support of the Companies’ environmental strategy, Dominion and Virginia Power remain committed to compliance with all applicable environmental laws, regulations and rules
related to our operations. Additional information related to our environmental compliance obligations can be found in Note 23 to the Consolidated Financial Statements.
Energy Efficiency and Peak Shaving Programs
In July 2009, Virginia Power filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of Virginia Power’s retail customers by ten percent of what was consumed in 2006. Virginia Power expects to launch the DSM programs in early 2010, subject to approval by the Virginia Commission and the North Carolina Commission, as applicable.
A key component of the plan is the demonstration of “smart grid” technologies that are designed to enhance Virginia Power’s electric distribution system by allowing energy to be delivered more efficiently. Dependent upon the outcome of demonstration and certain regulatory proceedings, Virginia Power may make a significant investment in replacing existing meters with Advanced Metering Infrastructure. The technology is expected to lead to improvements in service reliability and the ability of customers to monitor and control their energy use. Additionally, programs in the DSM plan include:

Incentives for construction of energy-efficient homes that meet the federal government’s Energy Star® standards;

Incentives for residential and commercial customers to install energy-efficient lighting;

Energy audits and improvements for homes of low-income customers;

Incentives for residential customers who voluntarily enroll to allow Virginia Power to cycle their air conditioners and heat pumps during periods of peak demand; and

Incentives for residential and commercial customers to improve the energy efficiency of their heating and/or cooling units.
REGULATION
Dominion and Virginia Power are subject to regulation by the Virginia Commission, North Carolina Commission, SEC, FERC, EPA, DOE, NRC, Army Corps of Engineers and other federal, state and local authorities.
State Regulations
ELECTRIC
Virginia Power’s electric utility retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.
Virginia Power holds certificates of public convenience and necessity which authorize it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, Virginia Power may not construct or incur financial commitments for construction of any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies. In addition, the Virginia Commission and the North Carolina
Commission regulate Virginia Power’s transactions with affiliates, transfers of certain facilities and the issuance of securities.
Electric Regulation in Virginia
In March 2009, Virginia Power filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also included a portion of costs discussed further in Federal Regulations. In a final order in June 2009, the Virginia Commission approved recovery of approximately $218 million through Rider T, which includes approximately $150 million of transmission-related costs that were traditionally incorporated in base rates, plus an incremental increase of approximately $68 million. The Virginia Commission also ruled that approximately $10 million that the Company had proposed to collect in Rider T would be more appropriately recovered through base rates, and those costs have been incorporated into the Company’s revised base rate filing that was submitted in July 2009. Rider T became effective on September 1, 2009, and increased a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.11 per month.
Virginia Power also has filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs, including one peak-shaving program and ten energy efficiency programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of the Company’s retail customers by ten percent of what was consumed in 2006. In February 2010, the Virginia Commission concluded an evidentiary hearing to consider the DSM programs and the related recovery. The Company has requested approval of two rate adjustment clauses for the associated cost recovery to be effective April 1, 2010. Specifically, the two rate adjustment clauses for recovery from Virginia jurisdictional customers represent an annual net increase in costs of approximately $48 million for the period April 1, 2010 to March 31, 2011. If approved by the Virginia Commission, the rate adjustment clauses will be expected, on a combined basis, to increase a typical 1,000 kWh residential bill by approximately $0.91 per month. The Regulation Act gives the Virginia Commission until the end of March 2010 to act on Virginia Power’s application.
In March 2009, Virginia Power filed with the Virginia Commission its first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to Rider S, plus the 100 basis point enhancement for construction of a new coal-fired generation facility, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009, at which Virginia Power presented a proposed Stipulation and Recommendation that, among other things, would reduce the increase in the revenue requirement by approximately $8 million to $91 million. In December 2009, the hearing examiner’s report
was issued recommending approval of the Rider S increase as set forth in the proposed Stipulation, and thereafter the Virginia Commission approved the Rider S increase consistent with this recommendation. The Rider S revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding.
In March 2009, Virginia Power also filed a petition with the Virginia Commission for recovery of approximately $77 million of construction-related financing costs associated with Bear Garden through the initiation of Rider R. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to the Bear Garden facility rate adjustment clause, with a 100 basis point enhancement for construction of a combined-cycle facility, as authorized by the Regulation Act, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009. In Virginia Power’s post-hearing brief, it unilaterally agreed to reduce the revenue requirement by $4 million to $73 million. In December 2009, the Virginia Commission approved Rider R with the $73 million revenue requirement for 2010. The Rider R revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding. In accordance with the Virginia Commission’s approval of Rider R, the enhanced return will apply to the Bear Garden facility during construction and through the first ten years of the facility’s service life.
In March 2009, Virginia Power filed its Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh, or approximately $3.64 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was held on September 1, 2009. Consistent with a proposal made by the Company at the hearing in September 2009, the Virginia Commission issued an interim fuel order, effective October 1, 2009, further reducing the fuel factor by approximately $103 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.529 cents per kWh to 3.310 cents per kWh, or approximately $2.19 per month for a typical 1,000 kWh Virginia jurisdictional residential customer’s bill. The cumulative decrease in the fuel factor for the period July 1, 2009 through June 30, 2010 reflects lower projected fuel expenses and a prospective credit against fuel expenses of certain FTRs allocated to the Company. In December 2009, the Virginia Commission issued another interim order decreasing Virginia Power’s fuel factor by approximately $119 million from 3.310 cents per kWh to 2.927 cents per kWh, a reduction of approximately $3.83 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill, for service rendered on and after January 1, 2010. The Virginia Commission has not yet issued a final order.
Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. In response, Virginia Power submitted base rate filings and accompanying schedules during 2009 to the Virginia
Commission, which, as amended, propose to increase its Virginia jurisdictional base rates by approximately $250 million annually. Virginia Power’s initial March 2009 filing proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on Virginia Power’s generating plant performance, customer service, and operating efficiency, resulting in a total ROE request of 13.5%. In July 2009, in response to rulings by the Virginia Commission relating to the appropriate rate year and capital structure to be used in the Company’s base rate review, Virginia Power submitted a revised filing reflecting a number of adjustments, including an upward adjustment of 50 basis points in the proposed ROE. The base rate increase became effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission and increases a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $5.22 per month.
In November 2009, Virginia Power and the Office of the Attorney General of Virginia, Division of Consumer Counsel, and certain other interested parties, filed a Stipulation and Recommendation for consideration and requested approval by the Virginia Commission that would resolve the pending proceeding to set base rates in Virginia, the Virginia fuel case proceeding and the authorized ROE for the rate adjustment clauses for the Virginia City Hybrid Energy Center, Bear Garden and the DSM programs. The November 2009 Stipulation entails, among other things, a partial refund of 2008 revenues and other amounts, an authorized ROE applicable to base rates of 11.9%, an authorized ROE applicable to the Virginia City Hybrid Energy Center and Bear Garden rate adjustment clauses of 12.3% and continuation of Virginia Power’s base rates in existence prior to September 1, 2009. An evidentiary hearing in the base rate review has been completed, at which evidence relating to both Virginia Power’s request for a base rate increase and the November 2009 Stipulation was presented. Not all of the parties to the base rate review or the related proceedings supported the November 2009 Stipulation. In February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission. As compared to the November 2009 Stipulation, the February 2010 Stipulation has the support of all parties, including the Staff of the Virginia Commission and reflects an increase in the amounts to be refunded to customers. Virginia Power’s 2009 results include a charge representing its best estimate of the probable outcome of this matter, which is discussed further in Note 14 to the Consolidated Financial Statements. Outcomes of the base rate review could include adoption of the terms of the February 2010 Stipulation, or alternatively, a rate increase, a rate decrease, or a partial refund of 2008 earnings deemed more than 50 basis points above the authorized ROE.
If the Virginia Commission’s future rate actions, including actions relating to Virginia Power’s 2009 base rate review, DSM programs, recovery of Virginia fuel expenses, and additional rate adjustment clause filings differ materially from Virginia Power’s expectations it could adversely affect its results of operations, financial condition and cash flows.
North Carolina Regulation
In 2004, the North Carolina Commission commenced a review of Virginia Power’s North Carolina base rates and subsequently ordered Virginia Power to file a general rate case to show cause
why its North Carolina jurisdictional base rates should not be reduced. The rate case was filed in September 2004, and in March 2005 the North Carolina Commission approved a settlement that included a prospective $12 million annual reduction in current base rates and a five-year base rate moratorium, effective as of April 2005. Fuel rates are still subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.
In February 2010, Virginia Power filed an application with the North Carolina Commission to increase its electric retail rates in North Carolina by approximately $46 million effective January 2011. The requested rate increase would consist of a base rate increase of approximately $29 million and approximately $17 million in purchased power costs to be recovered by means of the existing pass-through fuel adjustment charge. These purchased power costs have previously been considered part of the Company’s cost of service for recovery through base rates. The application entails a proposed ROE of 11.9%. The proposed base rate increase of $29 million would increase a typical 1,000 kWh North Carolina jurisdictional customer’s bill by approximately 9% or $8.96 per month when compared to residential bills under the currently approved rates. If the entire $17 million increase related to purchased power costs were to be approved for recovery in the 2011 fuel adjustment charge, and if none of those costs are offset by reductions in costs for other fuel types, the additional impact on residential customer bills would be approximately 5% or $4.94 per month. It is anticipated that a public hearing on the proposed base rate increase will be consolidated with the Company’s annual fuel adjustment proceeding in the fourth quarter of 2010 so as to facilitate a North Carolina Commission order in both matters before the end of 2010.
GAS
Dominion’s gas distribution services are regulated by the Ohio Commission, the Pennsylvania Commission and the West Virginia Commission.
Status of Competitive Retail Gas Services
Each of the three states in which Dominion has gas distribution operations has enacted or considered legislation regarding a competitive deregulation of natural gas sales at the retail level.
Ohio-Ohio has not enacted legislation requiring supplier choice for residential or commercial natural gas consumers. However, in cooperation with the Ohio Commission, Dominion has offered retail choice to residential and commercial customers. At December 31, 2009, approximately 1 million of Dominion’s 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, Dominion East Ohio implemented a pilot program approved by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program. Under the pilot program, Dominion East Ohio entered into gas purchase contracts with selected suppliers at a fixed price above the NYMEX month-end settlement. This Standard Service Offer pricing mechanism replaced the traditional gas cost recovery rate with a monthly market price that eliminated the true-up adjustment, making it easier for customers to compare and switch to competitive suppliers if they so choose.
In June 2008, the Ohio Commission approved a settlement filed in response to Dominion East Ohio’s application seeking
approval of Phase 2 of its plan to restructure its commodity service. Under that settlement, the existing Standard Service Offer program was continued through March 2009 with an update to the fixed rate adder to the NYMEX price. Starting in April 2009, Dominion East Ohio buys natural gas under the Standard Service Offer program for customers not eligible to participate in the Energy Choice program, but places Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which is designated on the customers’ bills. Subject to ultimate Ohio Commission approval, Dominion East Ohio may exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. Dominion East Ohio will continue to be the provider of last resort in the event of default by a supplier. Large industrial customers in Ohio also source their own natural gas supplies.
Pennsylvania-In Pennsylvania, supplier choice is available for all residential and small commercial customers of Peoples. At December 31, 2009, approximately 94,000 of Peoples’ 358,000 residential and small commercial customers had opted for Energy Choice in the Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.
West Virginia-At this time, West Virginia has not enacted legislation to require customer choice in the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.
Rates
Dominion’s gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate-Ohio, Pennsylvania and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general base rate increases to recover increased operating costs. In addition to general rate increases, Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. The majority of these purchased gas costs are subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one, three or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.
In the fourth quarter of 2008, the Ohio Commission approved an approximately $41 million annual revenue increase and an 8.49% allowed rate of return on rate base for Dominion East Ohio, which were reflected in revised rates commencing December 22, 2008.
In October 2008, Hope filed a request with the West Virginia Commission for an increase in the base rates it charges for natural gas service. The requested new base rates would have increased Hope’s revenues by approximately $34 million annually. In November 2009, the West Virginia Commission authorized an approximately $9 million increase in base rates.
Regulatory Approval of Sale of Peoples
In September 2008, Dominion and BBIFNA each filed a Premerger Notification and Report Form with the U.S. Department of Justice and the Federal Trade Commission under the HSR Act. In October 2008, the mandatory waiting period under the HSR Act related to the proposed sale of Peoples and Hope to the SteelRiver Buyer expired. In September 2009, Dominion and the SteelRiver Fund each filed a renewed Premerger Notification and Report Form with the U.S. Department of Justice and Federal Trade Commission. In October 2009, Dominion and the SteelRiver Fund were granted early termination of the mandatory waiting period under the HSR Act.
In September 2008, Peoples, Dominion and the SteelRiver Buyer filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by the SteelRiver Buyer of all of the stock of Peoples. In September 2009, Peoples, Dominion, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding reached a settlement on issues involved in the Peoples sale. In November 2009, the Pennsylvania Commission approved the settlement, thereby approving the sale of Peoples to the SteelRiver Buyer.
In October 2008, Hope, Dominion and the SteelRiver Buyer filed a joint petition seeking West Virginia Commission approval of the purchase by the SteelRiver Buyer of all of the stock of Hope. In December 2009, the West Virginia Commission denied the application for the sale of Hope.
Dominion decided to retain Hope, but continue with the sale of Peoples, which closed in February 2010.
Federal Regulations
EPACT AND THE REPEAL OF PUHCA
EPACT was signed into law in August 2005. Among other things, EPACT repealed PUHCA, which regulated many significant aspects of a registered holding company system, such as Dominion’s. As a result of PUHCA’s repeal, utility holding companies, including Dominion’s system, are no longer limited to a single integrated public utility system. Further, utility holding companies are no longer restricted from acquiring businesses that may not be related to the utility business. Jurisdiction over certain holding company related activities has been transferred to the FERC, including the issuance of securities by public utilities, the acquisition of securities of utilities, the acquisition or sale of certain utility assets, and the merger with another electric utility or holding company. In addition, both FERC and state regulators are permitted to review the books and records of any company within a holding company system.
EPACT contains key provisions affecting the electric power industry. These provisions include tax changes for the utility industry, incentives for emissions reductions and federal insurance and incentives to build new nuclear power plants. It gives the FERC “backstop” transmission siting authority, as well as increased utility merger oversight. The law also provides incentives and funding for clean coal technologies and initiatives to voluntarily reduce GHG emissions. FERC has issued regulations implementing EPACT. Dominion and Virginia Power do not expect compliance with these regulations to have a material adverse impact on their financial condition or results of operations.
FEDERAL ENERGY REGULATORY COMMISSION
Electric
Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Virginia Power purchases and sells electricity in the PJM wholesale market and Dominion’s merchant generators sell electricity in the PJM, MISO and ISO-NE wholesale markets under Dominion’s market-based sales tariffs authorized by FERC. In addition, Virginia Power has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside Virginia Power’s service territory. Any such sales would be voluntary. In May 2005, FERC issued an order finding that PJM’s existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings on the matter. In January 2008, FERC affirmed an earlier decision that the PJM transmission rate design for existing facilities had not become unjust and unreasonable. For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the U.S. Court of Appeals for the Seventh Circuit. In August 2009, the court denied the petition for review concerning the rate design for existing facilities, but granted the petition concerning the rate design for new facilities that operate at or above 500 kV, and remanded that issue back to FERC for further proceedings. Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand.
Dominion and Virginia Power are subject to FERC’s Standards of Conduct that govern conduct between transmission function employees of interstate gas and electricity transmission providers and the marketing function employees of their affiliates. The rule defines the scope of transmission and marketing-related functions that are covered by the standards and is designed to prevent transmission providers from giving their affiliates undue preferences.
Dominion and Virginia Power are also subject to FERC’s affiliate restrictions that (1) prohibit power sales between Virginia Power and Dominion’s merchant plants without first receiving FERC authorization, (2) require the merchant plants and Virginia Power to conduct their wholesale power sales operations separately, and (3) prohibit Virginia Power from sharing market information with merchant plant operating personnel. The rules are designed to prohibit Virginia Power from giving the merchant plants a competitive advantage.
EPACT included provisions to create an Electric Reliability Organization. The Electric Reliability Organization is required to promulgate mandatory reliability standards governing the operation of the bulk power system in the U.S. FERC has certified NERC as the Electric Reliability Organization and also issued an initial order approving many reliability standards that went into effect on January 1, 2007. Entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.
Dominion and Virginia Power have planned and operated their facilities in compliance with earlier NERC voluntary standards for many years and are aware of the new requirements. Dominion and Virginia Power participate on various NERC committees, track the development and implementation of standards, and maintain proper compliance registration with NERC’s regional organizations. While Dominion and Virginia Power expect that there will be some additional cost involved in maintaining compliance as standards evolve, they do not expect the operations and maintenance expenditures to be significant.
In April 2008, FERC granted an application for Virginia Power’s electric transmission operations to establish a forward-looking formula rate mechanism that updates transmission rates on an annual basis and approved an ROE of 11.4% on the common equity base of these operations, effective as of January 1, 2008. The formula rate is designed to cover the expected cost of service for each calendar year and is trued up based on actual costs. While other transmission owners in the PJM region use a formula rate based on historic costs, Virginia Power’s formula rate is based on projected costs. The FERC ruling did not materially impact Virginia Power’s results of operations; however, the FERC-approved formula method allows Virginia Power to earn a more current return on its growing investment in electric transmission infrastructure.
In July 2008, Virginia Power filed an application with FERC requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 150 basis points or 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 125 basis points or 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008 and rehearing is pending. Virginia Power cannot predict the outcome of the rehearing.
In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Commission, New Jersey Board of Public Utilities and several other organizations representing consumers in the PJM region (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. Dominion and Virginia Power cannot predict the outcome of the appeal.
In December 2008, FERC approved the Companies’ DRC request to become effective January 1, 2009, which allows recovery of approximately $153 million of Dominion’s RTO costs, including $140 million at Virginia Power, that were deferred due to a statutory base rate cap established under Virginia law. In June 2009, the Virginia Commission approved full recovery of the DRC from Virginia Power’s retail customers through Rider T. Recovery of the DRC began September 1, 2009. In July 2009, FERC issued an order denying the Office of the Attorney General of Virginia and the Virginia Commission’s requests for rehearing of its December 2008 order. Notices of appeal were filed in September 2009 at the U.S. Court of Appeals for the Fourth Circuit and the appeal is currently pending. In the fourth quarter of 2009, Dominion and Virginia Power wrote off substantially all of these regulatory assets, since recovery is no longer probable based on the proposed settlement of Virginia Power’s rate case proceedings discussed further in Note 14 to the Consolidated Financial Statements.
Gas
FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate natural gas company subsidiaries, including DTI, DCP and the Dominion South Pipeline Company, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.
Dominion’s interstate gas transmission and storage activities are generally conducted on an “open access” basis, in accordance with certificates, tariffs and service agreements on file with FERC.
Dominion is also subject to the Pipeline Safety Act of 2002 (2002 Act), which mandates inspections of interstate and intrastate natural gas transmission and storage pipelines, particularly those located in areas of high-density population. Dominion has evaluated its natural gas transmission and storage properties, as required by the Department of Transportation regulations under the 2002 Act, and has implemented a program of identification, testing and potential remediation activities. These activities are ongoing.
In May 2005, FERC approved a comprehensive rate settlement with Dominion’s subsidiary, DTI, and its customers and interested state commissions. The settlement, which became effective July 1, 2005, revised Dominion’s natural gas transmission rates and reduced fuel retention levels for storage service customers. As part of the settlement, DTI and all signatory parties agreed to a rate moratorium through June 30, 2010.
In December 2007, DTI and the Independent Oil and Gas Association of West Virginia, Inc. reached a settlement agreement on DTI’s gathering and processing rates for the period January 1, 2009 through December 31, 2011. This settlement maintained the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In connection with the settlement, DTI has committed to invest at least $20 million annually in Appalachian gathering-related assets. The new rates have been approved by FERC as negotiated rates.
Environmental Regulations
Each of Dominion’s and Virginia Power’s operating segments faces substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. If expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Companies. Dominion and Virginia Power have applied for or obtained the necessary environmental permits for the operation of their facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance required to be discussed in this Item, see Environmental Matters in Future Issues and Other Matters in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 23 to the Consolidated Financial Statements.
GLOBAL CLIMATE CHANGE
General
In recent years there has been increased national and international attention to GHG emissions and their relationship to climate change, which has resulted in federal, regional and state legislative or regulatory action in this area. Dominion and Virginia Power support national climate change legislation to provide a consistent, economy-wide approach to addressing this issue and are taking action to protect the environment and address climate change while meeting the future needs of their growing service territory. Dominion’s CEO and operating segment CEOs are responsible for compliance with the laws and regulations governing environmental matters, including climate change, and Dominion’s Board of Directors receives periodic updates on these matters.
Dominion developed a more comprehensive GHG inventory for calendar year 2008. For Dominion Generation, Dominion’s and Virginia Power’s direct CO2 equivalent emissions, based on equity share (ownership), were approximately 56 million metric tonnes and 33 million metric tonnes, respectively, in 2008. For the DVP operating segment’s electric transmission and distribution operations, direct CO2 equivalent emissions were approximately 0.2 million metric tonnes. DTI’s (including Dominion’s Cove Point LNG facility) direct CO2 equivalent emissions were approximately 2.5 million metric tonnes, Dominion East Ohio’s direct CO2 equivalent emissions were approximately 1.4 million metric tonnes and Dominion E&P’s direct CO2 equivalent emissions were approximately 0.7 million metric tonnes. While the Companies do not have final 2009 emissions data, they do not expect a significant variance in emissions from 2008 amounts. With respect to electric generation, primary facility stack emissions of CO2 from carbon based fuel combustion are directly measured via continuous emissions monitor system methods set forth under 40 CFR Part 75 of the United States Code. For those emission sources not covered under 40 CFR Part
75, and for methane and nitrous oxide emissions, quantification is based on fuel combustion, higher heating values, emission factors, and global warming potentials as specified in the new EPA Mandatory Reporting of Greenhouse Gases Rule, effective December 2009. Although the reporting rule does not apply until calendar year 2010 emissions, Dominion and Virginia Power have proactively implemented the data collection methodologies specified in the rule. For the DVP operating segment’s electric transmission and distribution emissions, the protocol used was The Climate Registry. For Dominion’s natural gas businesses, combustion related emissions were calculated using the EPA Mandatory Reporting of Greenhouse Gases Rule as described above. For DTI, the protocol used to calculate the non-combustion related emissions reported above was Greenhouse Gas Emission Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1-GHG Estimation Methodologies and Procedures-Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America. For Dominion East Ohio, the protocol used to calculate the non-combustion related emissions was the American Gas Association’s April 2008 Greenhouse Emissions Estimation Methodologies and Procedures for Natural Gas Distribution Operations. For Dominion E&P emissions, the protocol used was the American Petroleum Institute August 2009 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry.
Climate Change Legislation and Regulation
See Note 23 to the Consolidated Financial Statements for information on climate change legislation and regulation.
Physical Risks
Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Additionally, droughts can result in reduced water levels that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level.
Dominion and Virginia Power’s Strategy for Voluntarily Reducing GHG Emissions
While Dominion and Virginia Power have not established a standalone GHG emissions reduction target or timetable, they are actively engaged in voluntary reduction efforts and are working toward achieving the standards established by existing state regulations as set forth above. The Companies have an integrated strategy for reducing GHG emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, hydro and renewable energy, investing in renewable energy projects, and promoting energy conservation and efficiency efforts. See Environmental Strategy above for a description of Dominion and
Virginia Power’s strategy for reducing GHG emission intensity. Some recent efforts that have or are expected to reduce the Companies’ carbon intensity include:

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 technology. Virginia Power also converted two coal-fired units to cleaner burning natural gas.

Since 2000, Dominion has added more than 2,500 MW of non-emitting nuclear generation and approximately 3,050 MW of new lower-emitting natural gas-fired generation including 1,450 MW at Virginia Power (excluding Possum Point), to its generation mix.

Virginia Power has also added 83 MW of renewable biomass.

Dominion has completed electrical generation uprates of 120 MW at its gas-fired Fairless power station and 77 MW at Millstone.

Dominion has over 900 MW of wind energy in operation or development. Also, in April 2008, Virginia Power announced an agreement with BP to jointly develop, own and operate wind energy projects in Virginia.

In 2009, Virginia Power began constructing the 580 MW combined-cycle natural gas-fired Bear Garden generating facility.

Virginia Power has 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 2009, Virginia Power filed with the Virginia Commission for approval of eleven DSM programs, including the 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 ten percent biomass for fuel and was designed to be carbon-capture compatible, meaning that technology to capture CO2 can be added to the station when it becomes commercially available. Also, Virginia Power has announced plans to convert its coal units at Bremo power station to natural gas, contingent upon the Virginia City Hybrid Energy Center entering service and receipt of necessary approvals. It is currently estimated that the Virginia City Hybrid Energy Center will have the potential to emit about 4.8 million metric tonnes of direct CO2 emissions in a year assuming a 100% capacity factor and 100% coal-fired operation. Actual emissions will depend on the capacity factor of the facility, and the extent to which biomass is burned. See Dominion Generation-Properties for more information on the projects above, as well as other projects under current development.
Since 2000, the Companies have tracked the emissions of their electric generation fleet. Their electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2008, Dominion and Virginia Power’s electric generating fleet (based on ownership percentage) reduced their average CO2 emissions rate per MWh of energy
produced from electric generation by about 15% and 8%, respectively. During such time period the capacity of Dominion and Virginia Power’s electric generation fleet has grown.
Nuclear Regulatory Commission
All aspects of the operation and maintenance of nuclear power stations, which are part of the Dominion Generation segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.
From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion’s and Virginia Power’s nuclear generating units.
The NRC also requires Dominion and Virginia Power to decontaminate their nuclear facilities once operations cease. This process is referred to as decommissioning, and the Companies are required by the NRC to be financially prepared. For information on decommissioning trusts, see Dominion Generation-Nuclear Decommissioning and Note 10 to the Consolidated Financial Statements.
SPENT NUCLEAR FUEL
Under provisions of the Nuclear Waste Policy Act of 1982, Dominion and Virginia Power entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. A trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. On October 15, 2008, the Court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at its Surry and North Anna power stations and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Dominion’s Millstone power station through June 30, 2006. Judgment was entered by the Court on October 28, 2008. In December 2008, the government appealed the judgment to the U. S. Court of Appeals for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s request to stay the appeal. With the exception of one case, the Federal Circuit has issued such stays in all other currently pending appeals from spent fuel damages awards. In November 2009, Dominion and Virginia Power filed a motion to lift the stay and the government has opposed this motion. Once the stay is lifted, briefing on the appeal will take place. Payment of any damages will not occur until the appeal process has been resolved. Dominion and Virginia Power cannot predict the outcome of this matter; however, in the event that they recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on their results of operations.
A lawsuit was also filed for Dominion’s Kewaunee power station, and that lawsuit is presently stayed through March 15, 2010. The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Item 1A. Risk Factors
Dominion’s and Virginia Power’s businesses are influenced by many factors that are difficult to predict, involve uncertainties that may materially affect actual results and are often beyond their control. A number of these factors have been identified below. For other factors that may cause actual results to differ materially from those indicated in any forward-looking statement or projection contained in this report, see Forward-Looking Statements in Item 7. MD&A.
Dominion’s and Virginia Power’s results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require incurring additional expenses. Additionally, droughts can result in reduced water levels that could adversely affect operations at some of the Companies’ power stations. Furthermore, the Companies’ operations could be adversely affected and their physical plant placed at greater risk of damage should changes in global climate produce, among other possible conditions, unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and, for operations located on or near coastlines, a change in sea level.
Dominion and Virginia Power are subject to complex governmental regulation that could adversely affect their operations. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local regulation and require numerous permits, approvals and certificates from various governmental agencies. They must also comply with environmental legislation and associated regulations. Management believes that the necessary approvals have been obtained for existing operations and that their business is conducted in accordance with applicable laws. However, new laws or regulations, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may require Dominion and Virginia Power to incur additional expenses.
Virginia Power could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of bulk power transmission systems, including Virginia Power, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. If Virginia Power is found not to be in compliance with the mandatory reliability standards it could be subject to sanctions, including substantial monetary penalties.
Dominion’s and Virginia Power’s costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws could adversely affect their cash flow and profitability. Dominion’s and Virginia Power’s operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires the Companies to commit significant capital toward permitting, emission fees, environ -
mental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, they could be responsible for expenses relating to remediation and containment obligations, including at sites where they have been identified by a regulatory agency as a potentially responsible party. Expenditures relating to environmental compliance have been significant in the past, and Dominion and Virginia Power expect that they will remain significant in the future. Costs of compliance with environmental regulations could adversely affect their results of operations and financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets Dominion and Virginia Power operate increases. Compliance costs cannot be estimated with certainty due to the inability to predict the requirements and timing of implementation of any new environmental rules or regulations related to emissions. Other factors which affect the ability to predict future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties.
If federal and/or state requirements are imposed on energy companies mandating further emission reductions, including limitations on GHG emissions and reductions in SO2, NOx and mercury emissions and other environmental requirements relating to coal ash disposal and cooling water, such requirements may result in compliance costs that alone or in combination could make some of Dominion’s and Virginia Power’s electric generating units uneconomical to maintain or operate. As related to GHG emissions, the U.S. Congress, environmental advocacy groups, other organizations and some state and federal agencies are focusing considerable attention on GHG emissions from power generation facilities and their potential role in climate change. Dominion and Virginia Power expect that federal legislation and/or EPA regulation, and possibly additional state legislation and/or regulation, may pass resulting in the imposition of limitations on GHG emissions from fossil fuel-fired electric generating units. In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” If GHGs become regulated pollutants under the CAA, the Companies will be required to obtain permits for GHG emissions from new and modified facilities and amend operating permits for major sources of GHG emissions. Until these actions occur, and the EPA establishes guidance for GHG permitting, including Best Available Control Technology, it is not possible to determine the impact on Dominion’s and Virginia Power’s facilities that emit GHGs. However, such limits could make certain of the Companies’ electric generating units uneconomical to operate in the long term, unless there are significant advancements in the commercial availability and cost of carbon capture and storage technology. There are also potential impacts on Dominion’s natural gas businesses as federal GHG legislation may require GHG emission reductions from the natural gas sector and could affect demand for natural gas. Additionally, GHG requirements could result in increased demand for energy conservation and renewable products. Several regions of the U.S. have moved forward with GHG emission
regulations including regions where Dominion has operations. For example, Massachusetts has implemented regulations requiring reductions in CO2 emissions and the Regional Greenhouse Gas Initiative, a cap and trade program covering CO2 emissions from power plants in the Northeast, which affects several of Dominion’s facilities. In addition, a number of bills have been introduced in Congress that would require GHG emissions reductions from fossil fuel-fired electric generation facilities, natural gas facilities and other sectors of the economy, although none have yet been enacted. Compliance with these GHG emission reduction requirements may require committing significant capital toward carbon capture and storage technology, purchase of allowances and/or offsets, fuel switching, and/or retirement of high-emitting generation facilities and potential replacement with lower emitting generation facilities. The cost of compliance with expected GHG emission legislation and/or regulation is subject to significant uncertainties due to the outcome of several interrelated assumptions and variables, including timing of the implementation of rules, required levels of reductions, allocation requirements of the new rules, the maturation and commercialization of carbon capture and storage technology and associated regulations, and the selected compliance alternatives. As a result, Dominion and Virginia Power cannot estimate the effect of any such legislation on their results of operations, financial condition or their customers.
The base rates of Virginia Power are subject to regulatory review. As a result of the Regulation Act, in 2009, the Virginia Commission commenced its review of the base rates of Virginia Power under a modified cost-of-service model. Such rates will be set based on analyses of Virginia Power’s costs and capital structure, as reviewed and approved in regulatory proceedings. Under the Regulation Act, the Virginia Commission may, in a proceeding initiated in 2009, reduce rates or order a credit to customers if Virginia Power is deemed to be earning more than 50 basis points above an ROE level to be established by the Virginia Commission in that proceeding. After the initial rate case, the Virginia Commission will review the base rates of Virginia Power biennially and may order a credit to customers if it is deemed to have earned an ROE more than 50 basis points above an ROE level established by the Virginia Commission and may reduce rates if Virginia Power is found to have had earnings in excess of the established ROE level during two consecutive biennial review periods.
The rates of Virginia Power’s electric transmission operations and Dominion’s gas transmission operations are subject to regulatory review. Revenue provided by Virginia Power’s electric transmission operations and Dominion’s gas transmission operations is based primarily on rates approved by FERC. The profitability of these businesses is dependent on their ability, through the rates that they are permitted to charge, to recover costs and earn a reasonable rate of return on their capital investment.
Virginia Power’s wholesale charges for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism Virginia Power’s wholesale electric transmission cost of service is estimated and thereafter trued-up as appropriate to reflect actual costs allocated to Virginia Power by PJM. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that Virginia
Power’s wholesale revenue requirement is no longer just and reasonable.
Similarly, various rates and charges assessed by Dominion’s gas transmission businesses are subject to review by FERC. Dominion is required to file a general base rate review for the FERC-jurisdictional services of Cove Point, effective not later than July 31, 2011. At that time, Cove Point’s cost of service will be reviewed by the FERC, with rates set based on analyses of the Company’s costs and capital structure. The FERC-jurisdictional rates for DTI are the subject of a 2005 FERC-approved settlement. That settlement established a rate moratorium that continues in effect through June 30, 2010.
Energy conservation could negatively impact Dominion’s and Virginia Power’s financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of Dominion’s merchant generation, E&P assets and other unregulated business activities could be adversely impacted. In Virginia Power’s regulated operations, conservation could negatively impact its results depending on the regulatory treatment of the associated impacts. Should Virginia Power be required to invest in conservation measures that resulted in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. Dominion and Virginia Power are unable to determine what impact, if any, conservation will have on their financial condition or results of operations.
Dominion’s merchant power business is operating in a challenging market, which could adversely affect its results of operations and future growth. The success of Dominion’s merchant power business depends upon favorable market conditions including the ability to purchase and sell power at prices sufficient to cover its operating costs. Dominion operates in active wholesale markets that expose it to price volatility for electricity and fuel as well as the credit risk of counterparties. Dominion attempts to manage its price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.
In these wholesale markets, the spot market price of electricity for each hour is generally determined by the cost of supplying the next unit of electricity to the market during that hour. In many cases, the next unit of electricity supplied would be provided by generating stations that consume fossil fuels, primarily natural gas. Consequently the open market wholesale price for electricity generally reflects the cost of natural gas plus the cost to convert the fuel to electricity. Therefore changes in the price of natural gas generally affect the open market wholesale price of electricity. To the extent Dominion does not enter into long-term power purchase agreements or otherwise hedge its output, then these changes in market prices could adversely affect its financial results.
In addition, Dominion purchases fuel under a variety of terms, including long-term and short-term contracts and spot market purchases. Dominion is exposed to fuel cost volatility for the portion of its fuel obtained through short-term contracts or on the spot market. Fuel prices can be volatile and the price that can be obtained for power produced from such fuel may not change at the same rate as fuel costs, thus adversely impacting Dominion’s financial results.
Lastly, Dominion is exposed to credit risks of its counterparties and the risk that one or more counterparties may fail to perform under their obligations to make payments. Defaults by suppliers or other counterparties may adversely affect Dominion’s financial results.
Dominion’s merchant power business may be negatively affected by possible FERC actions that could weaken competition in the wholesale markets or affect pricing rules in the RTO markets. Dominion’s merchant generation stations operating in PJM, MISO and ISO-NE sell capacity, energy and ancillary services into wholesale electricity markets regulated by FERC. The wholesale markets allow these merchant generation stations to take advantage of market price opportunities, but also exposes them to market risk. Properly functioning competitive wholesale markets in PJM, MISO and ISO-NE depend upon FERC’s continuation of clearly identified market rules. From time to time FERC may investigate and authorize PJM, MISO and ISO-NE to make changes in market design. FERC also periodically reviews Dominion’s authority to sell at market-based rates. Material changes by FERC to the design of the wholesale markets or Dominion’s authority to sell power at market-based rates could adversely impact the future results of its merchant power business.
Dominion’s and Virginia Power’s operations could be affected by terrorist activities and catastrophic events that could result from terrorism. In the event that their generating facilities or other infrastructure assets are subject to potential terrorist activities, such activities could significantly impair their operations and result in a decrease in revenues and additional costs to repair and insure their assets, which could have a material adverse effect on their business. The effects of potential terrorist activities could also include the risk of a significant decline in the U.S. economy, and the decreased availability and increased cost of insurance coverage, any of which could negatively impact the Companies’ results of operations and financial condition.
Dominion and Virginia Power have incurred increased capital and operating expenses and may incur further costs for enhanced security in response to such risks.
There are risks associated with the operation of nuclear facilities. Dominion and Virginia Power operate nuclear facilities that are subject to risks, including their ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and ability to maintain adequate reserves for decommissioning, costs of replacement power, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. Decommissioning trusts and external insurance coverage are maintained to mitigate the financial exposure to these risks. However, it is possible that decommissioning costs could exceed the amount in the trusts or that costs arising from claims could exceed the amount of any insurance coverage.
The use of derivative instruments could result in financial losses and liquidity constraints. Dominion and Virginia Power use derivative instruments, including futures, swaps, forwards, options and FTRs, to manage commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts primarily in the natural gas market for trading purposes. The Companies could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform
under a contract. In the absence of actively-quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.
In addition, Dominion uses derivatives primarily to hedge its merchant generation and gas and oil production. The use of such derivatives to hedge future electric and gas sales may limit the benefit Dominion would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require Dominion to deposit funds or post letters of credit with counterparties to cover the fair value of covered contracts in excess of agreed upon credit limits. For instance, when commodity prices rise to levels substantially higher than the levels where they have hedged future sales, Dominion may be required to use a material portion of its available liquidity or obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results of operations.
Derivatives designated under hedge accounting to the extent not fully offset by the hedged transaction can result in ineffectiveness losses. These losses primarily result from differences in the location and specifications of the derivative hedging instrument and the hedged item and could adversely affect Dominion’s results of operations.
Dominion’s and Virginia Power’s operations in regards to these transactions are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. These market risks are beyond their control and could adversely affect their results of operations and future growth.
For additional information concerning derivatives and commodity-based trading contracts, see Market Risk Sensitive Instruments and Risk Management in Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Notes 2 and 8 to the Consolidated Financial Statements.
Dominion’s E&P business is affected by factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of Dominion’s assets. Factors that may affect Dominion’s financial results include, but are not limited to: damage to or suspension of operations caused by weather, fire, explosion or other events at Dominion’s or third-party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, Dominion’s ability to acquire additional land positions in competitive lease areas, drilling cost pressures, operational risks that could disrupt production, drilling rig availability and geological and other uncertainties inherent in the estimate of gas and oil reserves.
Declines in natural gas and oil prices could adversely affect Dominion’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues from the production of proved gas and oil reserves using trailing twelve month average natural gas and oil prices (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.
Dominion and Virginia Power may not complete plant construction or expansion projects that they commence, or they may complete projects on materially different terms or timing than initially anticipated and they may not be able to achieve the intended benefits of any such project, if completed. Several plant construction and expansion projects have been announced and additional projects may be considered in the future. Management anticipates that they will be required to seek additional financing in the future to fund current and future plant construction and expansion projects and may not be able to secure such financing on favorable terms. In addition, projects may not be able to be completed on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of their counterparties or vendors, or other factors beyond their control. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of the business of Dominion and Virginia Power following the projects may not meet expectations. Additionally, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Further, Dominion and Virginia Power may not be able to timely and effectively integrate the projects into their operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect their ability to realize the anticipated benefits from the plant construction and expansion projects.
An inability to access financial markets could affect the execution of Dominion’s and Virginia Power’s business plans. Dominion and Virginia Power rely on access to short-term money markets, longer-term capital markets and banks as significant sources of funding and liquidity for capital expenditures, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities primarily associated with Dominion’s merchant generation and gas and oil production. Management believes that the Companies will maintain sufficient access to these financial markets based upon their current credit ratings and market reputation. However, certain disruptions outside of Dominion’s and Virginia Power’s control may increase their cost of borrowing or restrict their ability to access one or more financial markets. Such disruptions could include delays in the current economic recovery, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, changes to their credit ratings or the failure of financial institutions on which they rely. Restrictions on the Companies’ ability to access financial markets may affect their ability to execute their business plans as scheduled.
Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase Dominion’s liabilities, which then could require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trusts to satisfy future obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit plans. Dominion has significant obligations in these areas and holds significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below expected return rates. A
decline in the market value of the assets may increase the funding requirements of the obligations to decommission Dominion’s nuclear plants and under its pension and other postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under Dominion’s pension and other postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension benefit plans. If the decommissioning trust funds and benefit plan assets are not successfully managed, Dominion’s results of operations and financial condition could be negatively affected.
Changing rating agency requirements could negatively affect Dominion’s and Virginia Power’s growth and business strategy. As of February 1, 2010, Dominion’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa2, stable outlook, by Moody’s; and BBB+, stable outlook, by Fitch. As of February 1, 2010, Virginia Power’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa1, positive outlook, by Moody’s; and A-, stable outlook, by Fitch. In order to maintain current credit ratings in light of existing or future requirements, Dominion and Virginia Power may find it necessary to take steps or change their business plans in ways that may adversely affect their growth and earnings. A reduction in Dominion’s credit ratings or the credit ratings of Virginia Power by Standard & Poor’s, Moody’s or Fitch could result in an increase in borrowing costs, loss of access to certain markets, or both, thus adversely affecting operating results and could require Dominion to post additional collateral in connection with some of its price risk management activities.
Potential changes in accounting practices may adversely affect Dominion’s and Virginia Power’s financial results. Dominion and Virginia Power cannot predict the impact that future changes in accounting standards or practices may have on public companies in general, the energy industry or their operations specifically. New accounting standards could be issued that could change the way they record revenues, expenses, assets and liabilities. These changes in accounting standards could adversely affect reported earnings or could increase reported liabilities.
Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on Dominion’s and Virginia Power’s operations. Dominion’s and Virginia Power’s business strategy is dependent on their ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect their business and future operating results.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
As of December 31, 2009, Dominion owned its principal executive office and three other corporate offices, all located in Richmond, Virginia. Dominion also leases corporate offices in other cities in which its subsidiaries operate. Virginia Power shares its
principal office in Richmond, Virginia, which is owned by Dominion. In addition, Virginia Power’s DVP and Generation segments share certain leased buildings and equipment. See Item 1. Business for additional information about each segment’s principal properties.
Dominion’s assets consist primarily of its investments in its subsidiaries, the principal properties of which are described here and in Item 1. Business.
Substantially all of Virginia Power’s property is subject to the lien of the Indenture of Mortgage securing its First and Refunding Mortgage Bonds. There were no bonds outstanding as of December 31, 2009; however, by leaving the indenture open, Virginia Power retains the flexibility to issue mortgage bonds in the future. Certain of Dominion’s merchant generation facilities are also subject to liens.
In 2007, Dominion sold its non-Appalachian E&P operations, whose historical results are included in the Corporate and Other segment. Dominion’s remaining Appalachian E&P operations, which are included in the Dominion Energy segment, do not qualify as significant gas and oil producing activities for 2009 or 2008. As a result, the following information only details Dominion’s gas and oil operations for 2007.
COMPANY-OWNED PROVED GAS AND OIL RESERVES
Estimated net quantities of proved gas and oil reserves were as follows:
bbl = barrel
(1) Ending reserves for 2007 included 0.3 million barrels of oil/condensate and 12.3 million barrels of NGLs.
Certain of Dominion’s subsidiaries file Form EIA-23 with the DOE which reports gross proved reserves, including the working interest shares of other owners, for properties operated by such subsidiaries. The proved reserves reported in the previous table represent Dominion’s share of proved reserves for all properties, based on its ownership interest in each property. For properties Dominion operates, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Dominion-owned proved reserves reported in the previous table, does not exceed five percent. Estimated proved reserves as of December 31, 2007 are based upon studies for each of Dominion’s properties prepared by its staff engineers and audited by Ryder Scott Company, L.P., an engineering firm registered by the Texas Board of Professional Engineers. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines.
QUANTITIES OF GAS AND OIL PRODUCED
Quantities of gas and oil produced follow:
bbl = barrel
The average realized price per mcf of gas with hedging results (including transfers to other Dominion operations at market prices) during 2007 was $5.99 and the average realized prices without hedging results per mcf of gas produced was $6.63. The average realized prices for oil with hedging results during 2007 was $37.78 per barrel and the average realized price without hedging results was $50.08 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during 2007 was $1.39.
NET WELLS DRILLED IN THE CALENDAR YEAR
The number of net wells completed follows:
POWER GENERATION
Dominion and Virginia Power generate electricity for sale on a wholesale and a retail level. The Companies supply electricity demand either from their generation facilities or through purchased power contracts. As of December 31, 2009, Dominion Generation’s total utility and merchant generating capacity was 27,507 MW.
The following table lists Dominion Generation’s utility and merchant generating units and capability, as of December 31, 2009:
VIRGINIA POWER UTILITY GENERATION
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Excludes 50% undivided interest owned by ODEC.
(2) Excludes 11.6% undivided interest owned by ODEC.
(3) Excludes 40% undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
DOMINION MERCHANT GENERATION
Note: (CT) denotes combustion turbine and (CC) denotes combined cycle.
(1) Subject to a lien securing the facility’s debt.
(2) Excludes 50% partnership interest owned by RCM Morgantown Power, Ltd. and Hickory Power LLC.
(3) Excludes 6.53% undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Corporation.
(4) Includes generating units that Dominion operates under leasing arrangements.
(5) Excludes 50% membership interest owned by J. POWER Elwood, LLC.
(6) Excludes 50% membership interest owned by BP.
(7) Excludes 50% membership interest owned by Shell.
Item 3. Legal Proceedings
From time to time, Dominion and Virginia Power are alleged to be in violation or in default under orders, statutes, rules or regulations relating to the environment, compliance plans imposed upon or agreed to by them, or permits issued by various local, state and federal agencies for the construction or operation of facilities. Administrative proceedings may also be pending on these matters. In addition, in the ordinary course of business, the Companies are involved in various legal proceedings. Dominion and Virginia Power believe that the ultimate resolution of these proceedings will not have a material adverse effect on their financial position, liquidity or results of operations.
See Regulation in Item 1. Business, Future Issues and Other Matters in Item 7. MD&A, and Notes 14 and 23 to the Consolidated Financial Statements for additional information on various environmental, rate matters and other regulatory proceedings to which Dominion and Virginia Power are parties.
In December 2006 and January 2007, Dominion submitted self-disclosure notifications to EPA Region 8 regarding three E&P facilities in Utah that potentially violated CAA permitting requirements. In July 2007, a third party purchased Dominion’s E&P assets in Utah, including these facilities. In September 2008, Dominion received a draft Consent Decree related to the potential CAA infractions, which imposes obligations on Dominion’s subsidiary, DEPI and the purchaser, including payment of a civil penalty to the U.S. Department of Justice in the amount of $250,000. In November 2009, the U.S. District Court, District of Utah, Northern Division entered the final Consent Decree. Per Dominion’s asset purchase agreement, the third-party purchaser paid the civil penalty as required by the Consent Decree.
In February 2009, DCP and its contractor Sheehan Pipeline Construction Company received notice from Maryland’s Attorney General’s Office that the Maryland Department of the Environment (MDE) had referred to them, for enforcement, alleged violations of state wetlands, water pollution, and sediment pollution laws during construction of a pipeline associated with the Cove Point expansion project in Maryland. This served notice that the MDE would be seeking civil penalties for some of the alleged violations. In May 2009, Dominion received a letter from the MDE detailing all alleged violations and their maximum penalty liabilities. In December 2009, the MDE entered into a consent order with Dominion and Sheehan dismissing its claims. Per the consent order, Dominion and Sheehan denied the MDE’s allegations, and agreed to pay $175,000 to the MDE and restore a pond. Of that penalty, Sheehan and its subcontractor agreed to pay $119,000; Dominion agreed to pay $56,000 and restore the pond.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at Dominion’s State Line and Kincaid power stations. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April, Dominion received a Notice and Finding of Violations from the EPA claiming new source review violations, new source performance standards violations, and Title V permit program violations pursuant to the CAA and the respective State Implementation Plans. Dominion is currently evaluating the impact of the Notice and cannot predict the outcome of this matter.
Item 4. Submission of Matters to a Vote of Security Holders
None.
Executive Officers of Dominion
Name and Age
Business Experience Past Five Years(1)
Thomas F. Farrell II (55)
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; President and COO of Dominion and CNG from January 2004 to December 2005.
Mark F. McGettrick (52)
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; President and CEO-Generation of Virginia Power from January 2003 to January 2006.
Paul D. Koonce (50)
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; CEO-Energy of Virginia Power from January 2004 to January 2006.
David A. Christian (55)
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 (52)
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; Vice President-Fossil & Hydro System Operations of Virginia Power from December 2003 to March 2005.
Gary L. Sypolt (56)
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; President-Transmission of Virginia Power from January 2003 to January 2006.
Robert M. Blue (42)
Senior Vice President - Public Policy and Environment of Dominion and DRS from February 2010 to date; 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; Counselor to former Virginia Governor Mark R. Warner and Director of Policy from January 2002 to May 2005.
Mary C. Doswell (51)
Senior Vice President-Alternative Energy Solutions of Virginia Power and DRS from April 2009 to date; Senior Vice President-Regulation and Integrated Planning of Dominion, Virginia Power and DRS from October 2007 to March 2009; Senior Vice President and CAO of Dominion from January 2003 to September 2007; President and CEO of DRS from January 2004 to September 2007.
James K. Martin (45)
Senior Vice President-Regulation and Integrated Planning of Virginia Power and DRS from April 2009 to date; Senior Vice President-Business Development & Generation Construction of Virginia Power and DEI from October 2007 to March 2009; Vice President-Fossil & Hydro Technical Services of Virginia Power from January 2006 to September 2007; Vice President-Fossil & Hydro Technical Services of DEI from April 2005 to September 2007; Vice President-Business Development of DEI from June 2000 to April 2005.
Steven A. Rogers (48)
Senior Vice President and CAO of Dominion and President and CAO of DRS from October 2007 to date; Senior Vice President and Chief Accounting Officer 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.
James F. Stutts (65)
Senior Vice President and General Counsel of Dominion and Virginia Power from January 2007 to date and CNG from January 2007 to June 2007; Vice President and General Counsel of Dominion from September 1997 to December 2006; Vice President and General Counsel of Virginia Power from January 2002 to December 2006; Vice President and General Counsel of CNG from September 1999 to December 2006.
Name and Age
Business Experience Past Five Years(1)
Carter M. Reid (41)
Vice President-Governance and Corporate Secretary of Dominion and Virginia Power from December 2007 to date; Vice President-Governance of Dominion from October 2007 to November 2007; Director Executive Compensation and Legal Advisor of DRS from February 2006 to September 2007; Director Executive Compensation of DRS from July 2003 to January 2006.
Ashwini Sawhney (60)
Vice President and Controller (Chief Accounting Officer) of Dominion from July 2009 to date; 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.
(1) Any service listed for Virginia Power, CNG, DTI, DEI and DRS reflects service at a subsidiary of Dominion.
Part II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
DOMINION
Dominion’s common stock is listed on the New York Stock Exchange. At February 1, 2010, there were approximately 148,000 registered shareholders, including approximately 54,000 certificate holders. 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 Note 21 to the Consolidated Financial Statements. Cash dividends were paid quarterly in 2009 and 2008. Quarterly information concerning stock prices and dividends is disclosed in Note 29 to the Consolidated Financial Statements.
The following table presents certain information with respect to Dominion’s common stock repurchases during the fourth quarter of 2009.
DOMINION PURCHASES OF EQUITY SECURITIES
(1) Amount reflects registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.
(2) The remaining repurchase authorization is pursuant to repurchase authority granted by the Dominion Board of Directors in February 2005, as modified in June 2007.
(3) Represents the weighted-average price paid per share during the fourth quarter of 2009.
VIRGINIA POWER
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:
Item 6. Selected Financial Data
DOMINION
(1) Amounts attributable to Dominion’s common shareholders.
2009 results include a $435 million after-tax charge in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings. For more information see 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 a $136 million after-tax net income benefit due to the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope. In addition, 2008 includes $109 million after-tax charges reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts.
2007 results include a $1.5 billion after-tax net income 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 as discussed in Note 4 to the Consolidated Financial Statements. 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 regulation to the Virginia jurisdiction of Virginia Power’s generation operations in 2007 resulted in a $158 million after-tax extraordinary charge. See Note 2 to the Consolidated Financial Statements.
2006 results include a $104 million after-tax charge resulting from the write-off of certain regulatory assets related to the planned sale of Peoples and Hope. In addition, 2006 reflects the net impact of the discontinued operations of Canadian E&P operations sold in June 2007 and the Peaker facilities sold in March 2007. Discontinued operations for the Peaker facilities included a $164 million after-tax impairment charge to reduce the facilities’ carrying amount to its estimated fair value less cost to sell. See Note 4 to the Consolidated Financial Statements.
2005 results include a $272 million after-tax loss related to the discontinuance of hedge accounting for certain gas and oil derivatives, resulting from an interruption of gas and oil production in the Gulf of Mexico caused by Hurricanes Katrina and Rita.
VIRGINIA POWER
2009 results include a $427 million after-tax charge in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings. For more information see Note 14 to the Consolidated Financial Statements.
2007 results reflect the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations, which resulted in a $158 million after-tax extraordinary charge. See Note 2 to the Consolidated Financial Statements.
2005 results reflect the net impact of the discontinued operations of Virginia Power’s indirect wholly-owned subsidiary, Virginia Power Energy Marketing, Inc., which was transferred to Dominion through a series of dividend distributions on December 31, 2005.
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

Selected Information-Energy Trading Activities

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,” “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 greenhouse gases 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’ generation facilities;

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

Counterparty credit 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;

Completion and timing of the planned monetization of Dominion’s Marcellus Shale assets;

Changes in rules for RTOs 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;

Changes to regulated electric rates collected by Virginia Power, including the outcome of the base rate review initiated in 2009;

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.
Dominion and Virginia Power’s forward-looking statements are based on beliefs and assumptions using information available at the time the statements are made. The Companies caution the reader not to place undue reliance on their forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. Dominion and Virginia Power undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.
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 con -
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
dition 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.
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.
As discussed further in Note 2 to the Consolidated Financial Statements, in April 2007, Virginia Power reapplied accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations resulting in a $259 million ($158 million after-tax) extraordinary charge and the reclassification of $195 million ($119 million after-tax) of unrealized gains from AOCI related to nuclear decommissioning trust funds. This established a $454 million long-term regulatory liability for amounts previously 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 nuclear generation stations, in excess of the related ARO. In connection with the reapplication of this guidance, Virginia Power prospectively changed certain of its accounting policies for the Virginia jurisdiction of its generation operations to those used by cost-of-service rate-regulated entities. Other than the extraordinary item previously discussed, the overall impact of these changes was not material to Virginia Power’s results of operations or financial condition in 2007.
As discussed in Note 14 to the Consolidated Financial Statements, in February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission that could resolve its pending rate proceedings in Virginia. Virginia Power’s 2009 results include a charge of $782 million ($477 million after-tax) representing its best estimate of the probable outcome of this matter. Of this amount, $700 million ($427 million after-tax) represents a partial refund of 2008 revenues and other amounts, and $82 million ($50 million after-tax) represents an expected refund of 2009 revenues collected from customers as a result of the implementation of a base rate increase that became effective on an interim basis on September 1, 2009. Of the total $782 million pre-tax charge, $523 million was recorded in operating revenue, $129 million was recorded in electric fuel and other energy-related purchases expense, and $130 million was
recorded in other operations and maintenance expense in Virginia Power’s Consolidated Statement of Income. The charge resulted in a $259 million decrease in regulatory assets, reflecting the write off of $129 million of previously deferred fuel costs and $130 million of previously deferred RTO costs since recovery is no longer probable based on the proposed February 2010 Stipulation, as well as a $473 million increase in regulatory liabilities with the remainder recorded to other receivables and payables in Virginia Power’s Consolidated Balance Sheet. Dominion’s 2009 results include an additional charge of $12 million ($8 million after-tax) recorded in other operations and maintenance expense, reflecting the write-off of previously deferred RTO costs since recovery is no longer probable based on the proposed February 2010 Stipulation.
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. In 2006, Dominion wrote off $166 million of its regulatory assets as a result of the planned sale of Peoples and Hope to Equitable since the recovery of those assets was no longer probable. In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. Dominion continued to seek other offers for the purchase of these utilities and in July 2008 entered into an agreement with the SteelRiver Buyer to sell Peoples and Hope and recognized a benefit of $47 million due to the re-establishment of certain of these regulatory assets. In September 2009, Dominion recorded a reduction to these regulatory assets of $22 million. 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 2009, 2008 and 2007, Dominion recognized $89 million, $94 million and $99 million, respectively, of accretion, and expects to incur $88 million in 2010. In 2009, 2008 and 2007, Virginia Power recognized
$35 million, $38 million and $38 million, respectively, of accretion, and expects to incur $36 million in 2010. Upon reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations, Virginia Power began recording accretion and depreciation associated with utility nuclear decommissioning AROs, formerly charged to expense, as an adjustment to the regulatory liability for nuclear decommissioning trust funds previously discussed, in order to match the recognition for rate-making purposes.
A significant portion of the Companies’ AROs relates to the future decommissioning of their nuclear facilities. These nuclear decommissioning AROs are reported in the Dominion Generation segment. At December 31, 2009, Dominion’s nuclear decommissioning AROs totaled $1.3 billion, representing approximately 81% of its total AROs. At December 31, 2009, Virginia Power’s nuclear decommissioning AROs totaled $587 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, 2009, Dominion had $291 million and Virginia Power had $121 million of unrecognized tax benefits. For the majority 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 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 evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies may affect the realization of deferred tax assets. 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, 2009, Dominion had established $62 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 the 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 to 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.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING
As of December 31, 2009, Dominion reported $3.4 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 2009, 2008 and 2007 annual tests did not result in the recognition of any goodwill impairment.
As a result of the 2007 disposition of Dominion’s non-Appalachian E&P operations, goodwill was allocated to such operations based on the relative fair values of the E&P operations being disposed of and the Appalachian portion being retained. The impairment test performed on the goodwill allocated to the retained Appalachian operations showed no impairment. Also, in connection with the 2007 segment realignment, the goodwill allocated to Dominion’s three gas distribution subsidiaries was tested for impairment during the fourth quarter of 2007. This interim test did not result in the recognition of any goodwill impairment, as the estimated fair values of these businesses exceeded their respective carrying amounts.
In December 2009, Dominion made the decision to retain Hope and include it with Dominion 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 as no events occurred that would more-likely-than-not reduce the reporting units’ fair values below their carrying values.
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 non-Appalachian E&P operations, Peoples and Hope and certain DCI operations, negotiated sales prices were used as fair value for the tests conducted in 2009, 2008 and 2007. 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.
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 circumstances that 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.
In the third quarter of 2008, Dominion tested SO2 emissions allowances held for consumption, with a carrying amount of $144 million, as a result of a decline in the market value of such allowances resulting from the July 2008 D.C. Appeals Court decision vacating CAIR that affected certain emission allowance surrender ratios. Based on the results of Dominion’s test, including an analysis of recoverability through undiscounted cash flows from plant operations, no impairment charges were recognized. In December 2008, the court issued a decision to reinstate CAIR that resulted in an increase in the market value of SO2 allowances. As a result of a decline in SO2 allowance prices during 2009, Dominion updated its fair value assessment of excess allowances quarterly in 2009. Based on the result of these assessments, Dominion did not record any impairment adjustments.
In 2006, Dominion tested Dresden for impairment and concluded that its carrying amount, as well as the estimated cost to complete, was recoverable based on the probability of continued construction and use at that time. As part of Dominion’s ongoing asset review to improve its return on invested capital, Dominion began the process of exploring the sale of Dresden in the second quarter of 2007. Non-binding indicative bids were received and based on its evaluation of these bids, Dominion believed that it was likely that Dresden would be sold rather than completed and operated in its merchant fleet. This change in intended use represented a triggering event for Dominion to evaluate whether it could recover the carrying amount of its investment in Dresden. This analysis indicated that the carrying amount of Dresden would not be recovered. As a result, in the second quarter of 2007, Dominion recognized a $387 million ($252 million after- tax) impairment charge to reduce Dresden’s carrying amount to its estimated fair value in connection with the planned sale of Dresden, which closed in September 2007.
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 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 34% U.S. equity, 12% non-U.S. equity, 22% fixed income, 7% real estate and 25% other, 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 2009 and 2008, and 8.75% for 2007. Dominion calculated its other postretirement benefit cost using an expected long-term rate of return on plan assets assumption of 7.75% for 2009 and 2008, and 8.00% for 2007. 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 2009, compared to 6.60% and 6.50%, respectively, in 2008 and 6.20% and 6.10%, respectively, in 2007. Dominion selected a discount rate of 6.60% for determining its December 31, 2009 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, 2009 is 8.0% and is expected to gradually decrease to 4.90% 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:
In addition to the effects on cost, at December 31, 2009, a 0.25% decrease in the discount rate would increase Dominion’s projected pension benefit obligation by $126 million and its accumulated postretirement benefit obligation by $45 million, while a 1.00% increase in the healthcare cost trend rate would increase its accumulated postretirement benefit obligation by $191 million. See Note 22 to the Consolidated Financial Statements for additional information.
ACCOUNTING FOR GAS AND OIL OPERATIONS
Dominion follows the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depleted using the units-of-production method. Capitalized costs in the depletable base are subject to a ceiling test prescribed by the SEC. Dominion performs the ceiling test quarterly and recognizes asset impairments to the extent that total capitalized costs exceed the ceiling. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost pool.
Dominion’s estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. Dominion’s estimated proved reserves as of December 31, 2009 are based upon studies for each of its properties prepared by staff engineers and audited by Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petro -
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
leum industry and in accordance with SEC guidelines. Given the volatility of natural gas and oil prices, it is possible that Dominion’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near-term.
The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of Dominion’s estimates or assumptions in the future and revisions to the value of its proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2, 4 and 27 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 $355 million and $341 million of accrued unbilled revenue at December 31, 2009 and 2008, 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, 2008 and 2007, 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:
Overview
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 proposed settlement of Virginia Power’s 2009 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.
2008 VS. 2007
Net income attributable to Dominion decreased by 28%. Unfavorable drivers include the absence of a $2.1 billion after-tax gain on the sale of Dominion’s U.S. non-Appalachian E&P business and the absence of ongoing earnings from this business due to the sale. Favorable drivers include the absence of the following items incurred in 2007:

Charges related to the sale of the majority of its E&P operations;

An impairment charge related to the sale of Dresden;

An extraordinary charge in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations; and

A charge in connection with the termination of a long-term power sales agreement at State Line.
Additional favorable drivers include the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of Virginia Power’s generation operations effective July 1, 2007, a higher contribution from merchant generation operations and the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope. Diluted EPS decreased to $3.16 and includes $0.36 of share accretion resulting from the repurchase of shares in 2007 with proceeds received from the sale of the majority of Dominion’s E&P operations.
Analysis of Consolidated Operations
Presented below are selected amounts related to Dominion’s results of operations:
An analysis of Dominion’s results of operations follows:
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 proposed settlement of Virginia Power’s 2009 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 17%, 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 proposed settlement of Virginia Power’s 2009 rate case proceedings;

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

A $69 million increase reflecting the absence of the net benefit recorded in 2008 related to the re-establishment of a regulatory asset in connection with the planned sale of Peoples and Hope ($47 million) and a 2009 charge due to a reduction in this regulatory asset ($22 million); 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 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 increased $239 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 30%, primarily reflecting lower pre-tax income in 2009.
2008 VS. 2007
Net Revenue increased 6%, primarily reflecting:

A $500 million increase from merchant generation operations, primarily reflecting higher realized sales prices for nuclear and fossil operations ($500 million) and the absence of a charge related to the termination of a long-term power sales agreement at State Line in 2007 ($231 million), partially offset by lower overall sales volumes due to outages at certain fossil and nuclear generating facilities ($105 million), increased fuel expenses primarily reflecting the impact of higher commodity prices ($54 million) and increased fuel consumption ($72 million) at certain fossil generation facilities;

A $453 million increase in net revenue from electric utility operations resulting primarily from the reinstatement of annual fuel rate adjustments, effective July 1, 2007, for the Virginia jurisdiction of Virginia Power’s generation operations, with deferred fuel accounting for over- or under-recoveries of fuel costs; and
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued

A $129 million increase in sales of gas production from Dominion’s remaining E&P operations, primarily due to:

A $70 million increase in sales from Appalachian properties due to higher prices ($51 million) and increased production ($19 million); and

Increased production associated with VPP royalty interests ($59 million).
These increases were partially offset by:

A $656 million decrease due to the sale of the majority of U.S. E&P operations in 2007, reflecting the absence of $1.4 billion of net revenue from these operations, partially offset by the absence of a $541 million charge predominantly due to the discontinuance of hedge accounting for certain gas and oil derivatives and subsequent changes in the fair value of these derivatives; and a $171 million charge primarily due to the termination of VPP agreements in connection with the sale.
Other operations and maintenance expense decreased 21%, primarily reflecting the combined effects of:

A $443 million decrease reflecting the sale of the majority of U.S. E&P operations, including the absence of charges incurred in 2007 in connection with the sale;

The absence of a $387 million impairment charge in 2007 related to the sale of Dresden; and

The absence of $54 million of litigation-related charges in 2007.
Gain on sale of U.S. non-Appalachian E&P business primarily reflects the absence of the gain of $3.6 billion resulting from the completion of the sale of Dominion’s U.S. non-Appalachian E&P business in 2007.
DD&A decreased 24%, principally due to decreased gas and oil production resulting from the sale of the majority of U.S. E&P operations in 2007, partially offset by an increase in rates and production from remaining E&P operations, property additions and an increase in depreciation rates for utility generation assets.
Other taxes decreased 10%, primarily due to lower severance and property taxes resulting from the sale of the majority of U.S. E&P operations in 2007.
Other income (loss) was a loss of $58 million in 2008 as compared to income of $102 million in 2007, primarily due to higher other-than-temporary impairments for nuclear decommissioning trust investments.
Interest and related charges decreased 28%, resulting principally from the absence of charges related to the early extinguishment of outstanding debt associated with Dominion’s debt tender offer completed in July 2007 and lower interest rates on variable rate debt.
Income tax expense decreased by 51%, primarily due to lower pre-tax income in 2008 largely reflecting the absence of the gain realized in 2007 from the sale of Dominion’s U.S. non-Appalachian E&P business.
Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 in connection with the reapplication of guidance for accounting for certain types of regulation to the Virginia jurisdiction of Virginia Power’s generation operations.
Outlook
In order to deliver favorable returns to investors, Dominion’s strategy is to focus 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 stable credit ratings. In 2010, Dominion believes its operating businesses will provide stable growth in net income on a per share basis, including the impact of higher expected average shares outstanding. Dominion’s anticipated 2010 results reflect the following significant factors:

The absence of an impairment charge in 2009 related to the carrying value of Dominion’s E&P properties due to declines in gas and oil prices;

The absence of a charge in 2009 in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings;

A benefit from rate adjustment clauses associated with the recovery of construction-related financing costs for Bear Garden and Virginia City Hybrid Energy Center;

Minimal exposure to commodity prices reflecting hedges in place due to Dominion’s commodities hedging program;

Favorable interest rates reflecting hedges in place for Dominion’s and Virginia Power’s planned debt issuances in 2010;

The planned monetization of Dominion’s Marcellus Shale acreage with proceeds used to offset its anticipated 2010 equity financing needs;

Implementation of operations and maintenance cost-containment measures; and

An expected after-tax loss, as well as after-tax expenses, including transaction and benefit-related costs, in connection with the February 2010 sale of Peoples discussed in Note 4 to the Consolidated Financial Statements.
If the final resolution of Virginia Power’s 2009 rate case proceedings differs materially from management’s expectations it could adversely affect Dominion’s results of operations, financial condition and cash flows. See Forward-Looking Statements for additional factors that could cause actual results to differ materially from predicted results.
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:
DVP
Presented below are operating statistics related to DVP’s operations:
(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.
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2009 VS.
(1) Reflects the incremental impact of a rate adjustment clause associated with the recovery of transmission-related expenditures.
(2) Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.
(3) Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009.
2008 VS. 2007
(1) Reflects an increase in storm damage and service restoration costs resulting from more severe weather during 2008.
Dominion Generation
Presented below are operating statistics related to Dominion Generation’s operations:
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
VS. 2008
(1) Reflects the incremental impact of a rate adjustment clause associated with the recovery of construction-related financing costs for the Virginia City Hybrid Energy Center.
(2) Primarily reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
2008 VS. 2007
(1) Primarily reflects the reapplication of deferred fuel accounting effective July 1, 2007 for the Virginia jurisdiction of Virginia Power’s generation operations.
(2) Primarily reflects higher margins associated with sales to wholesale customers.
Dominion Energy
Presented below are operating statistics related to Dominion Energy’s operations:
(1) Thirteen-month average.
(2) Includes natural gas, NGLs and oil. Production includes 2.3 bcfe, 17.8 bcfe and 15.5 bcfe for 2009, 2008 and 2007, respectively, associated with VPP royalty interests.
(3) The inclusion of volumes associated with VPP royalty interests would have resulted in lifting costs of $1.17, $1.11 and $1.00 for 2009, 2008 and 2007, respectively.
Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s net income contribution:
2009 VS. 2008
(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.
2008 VS. 2007
(1) Primarily reflects an increase in volumes associated with VPP royalty interests.
Included below are the volumes and weighted-average prices associated with hedges in place for Dominion’s Appalachian E&P operations as of December 31, 2009, by applicable time period.
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results:
SPECIFIC ITEMS ATTRIBUTABLE TO OPERATING SEGMENTS
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.
SALE OF U.S. E&P BUSINESS
The sale of Dominion’s U.S. non-Appalachian E&P business reflects the $2.1 billion after-tax gain recognized in 2007 on the sale, partially offset by charges related to the divestitures as well as charges associated with the early retirement of debt with proceeds from the sale. The 2008 amount reflects post-closing adjustments to the gain on the sale. See Note 4 to the Consolidated Financial Statements for discussion of these items.
PEOPLES OPERATIONS
Income from Peoples decreased $45 million in 2009 as compared to 2008 and increased $26 million in 2008 as compared to 2007 primarily reflecting a $47 million ($28 million after-tax) benefit in 2008 from the re-establishment of certain regulatory assets in connection with the agreement to sell these subsidiaries to the SteelRiver Buyer. Regulatory assets of $166 million ($104 million after-tax) were written off in 2006 in connection with the previous sales agreement with Equitable. See Notes 4 and 6 to the Consolidated Financial Statements for discussion of these items.
OTHER CORPORATE OPERATIONS
The net expenses associated with other corporate operations for 2009 increased by $93 million as compared to 2008, primarily due to the absence of the following 2008 items:

Tax benefits due to the reversal of deferred tax liabilities associated with Peoples and Hope; partially offset by

Impairment charges related to the disposition of certain DCI investments.
The net expenses associated with other corporate operations for 2008 increased by $27 million as compared to 2007, primarily reflecting a decrease in tax benefits, higher interest expense and the absence of interest income earned on the proceeds received from the sale of Dominion’s non-Appalachian E&P business in 2007. The decrease in tax benefits primarily reflects the net impact of the following items:

A decrease in state tax benefits, including the impact of Massachusetts tax legislation enacted in July 2008; and

The absence of tax benefits from the elimination of valuation allowances on federal and state tax loss carryforwards in 2007; partially offset by

An increase in tax benefits due to the reversal of deferred tax liabilities associated with Peoples and Hope in 2008.
The increase in net expenses was partially offset by the impact of lower impairment charges in 2008 related to the disposition of certain DCI investments.
SELECTED INFORMATION-ENERGY TRADING ACTIVITIES
Dominion engages in energy trading, marketing and hedging activities to complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, Dominion enters into contracts for purchases and sales of energy-related commodities, including electricity, natural gas and other energy-related products. Settlements of contracts may require physical delivery of the underlying commodity or cash settlement. Dominion also enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, Dominion typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, Dominion may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Dominion continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity.
A summary of the changes in the unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes follows:
The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes at December 31, 2009, is summarized in the following table based on the approach used to determine fair value:
(1) Values represent observable unadjusted quoted prices for traded instruments in active markets.
(2) Values with inputs that are observable directly or indirectly for the instrument, but do not qualify for Level 1.
(3) Values with a significant amount of inputs that are not observable for the instrument.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
VIRGINIA POWER
RESULTS OF OPERATIONS
Presented below is a summary of Virginia Power’s consolidated results:
Overview
2009 VS. 2008
Net income decreased 59%, primarily due to a charge in connection with the proposed settlement of the 2009 rate case proceedings and an increase in outage costs related to scheduled outages at certain nuclear and fossil generating facilities.
2008 VS. 2007
Net income increased 93%, primarily due to the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of Virginia Power’s generation operations effective July 1, 2007, with deferred fuel accounting for over- or under-recoveries of fuel costs, and the absence of an extraordinary charge incurred in 2007 in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations.
Analysis of Consolidated Operations
Presented below are selected amounts related to Virginia Power’s results of operations:
An analysis of Virginia Power’s results of operations follows:
2009 VS. 2008
Net Revenue decreased 16%, primarily due to a charge for the proposed settlement of the 2009 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 proposed settlement of Virginia Power’s 2009 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; 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.
2008 VS. 2007
Net Revenue increased 13%, primarily reflecting the reinstatement of annual fuel rate adjustments, effective July 1, 2007, for the Virginia jurisdiction of Virginia Power’s generation operations, with deferred fuel accounting for over- or under-recoveries of fuel costs.
Other operations and maintenance expense increased 1%, primarily reflecting:

A $69 million increase resulting from higher salaries, wages and other benefits expenses and other general and administrative costs; partially offset by

A $58 million decrease in outage costs resulting from a reduction in scheduled outages at certain electric generating facilities.
Depreciation and amortization expense increased 7%, primarily due to an increase in depreciation rates for generation assets ($36 million) and property additions ($15 million), partially offset by an $11 million decrease in amortization expense primarily associated with lower consumption of emissions allowances.
Interest and related charges increased 2%, primarily due to a $43 million impact from additional borrowings, partially offset by a $23 million benefit related to the redemption of Virginia Power’s Callable and Puttable Enhanced Securities due to a difference between the amount of interest expense accrued and the amount of interest expense paid and lower interest rates on variable rate debt ($15 million).
Income tax expense increased 35%, reflecting higher pre-tax income in 2008.
Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations.
Outlook
Virginia Power expects to provide stable growth in net income in 2010. Virginia Power’s anticipated 2010 results reflect the following significant factors:

The absence of a charge in 2009 in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings;

A benefit from rate adjustment clauses associated with the recovery of construction-related financing costs for Bear Garden and Virginia City Hybrid Energy Center; and

Favorable interest rates reflecting hedges in place for Virginia Power’s planned debt issuances in 2010.
If the final resolution of Virginia Power’s 2009 rate case proceedings differs materially from management’s expectations it could adversely affect Virginia Power’s results of operations, financial condition and cash flows. See Forward-Looking Statements for additional factors that could cause actual results to differ materially from predicted results.
SEGMENT RESULTS OF OPERATIONS
Presented below is a summary of contributions by Virginia Power’s operating segments to net income:
DVP
Presented below are operating statistics related to Virginia Power’s DVP segment:
(1) Includes electricity delivered through the retail choice program for Virginia jurisdictional electric customers.
(2) 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.
(3) 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.
(4) Thirteen-month average.
Presented below, on an after-tax basis, are the key factors impacting DVP’s net income contribution:
2009 VS.
(1) Reflects the incremental impact of a rate adjustment clause associated with the recovery of transmission-related expenditures.
(2) Primarily reflects the impact of unfavorable economic conditions on customer usage and other factors.
(3) Reflects a decrease in storm damage and service restoration costs associated with electric distribution operations resulting from less severe weather during 2009.
2008 VS. 2007
(1) Reflects an increase in storm damage and service restoration costs resulting from more severe weather during 2008.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Dominion Generation
Presented below are operating statistics related to Virginia Power’s Dominion Generation segment:
Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s net income contribution:
2009 VS. 2008
(1) Reflects the incremental impact of a rate adjustment clause associated with the recovery of construction-related financing costs for the Virginia City Hybrid Energy Center.
(2) Primarily reflects lower sales to wholesale customers, as well as the impact of unfavorable economic conditions on customer usage and other factors.
2008 VS. 2007
(1) Primarily reflects the reapplication of deferred fuel accounting effective July 1, 2007, for the Virginia jurisdiction of Virginia Power’s generation operations.
(2) Primarily reflects higher margins associated with wholesale customers.
Corporate and Other
Presented below are the Corporate and Other segment’s after-tax results.
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, 2009, Dominion had $3.3 billion of unused capacity under its credit facilities, including $2.3 billion of unused capacity under a joint credit facility available to Virginia Power. See additional discussion under Credit Facilities and Short-Term Debt.
A summary of Dominion’s cash flows is presented below:
(1) 2009, 2008 and 2007 amounts include $2 million, $5 million and $4 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:
Operating Cash Flows
In 2009, net cash provided by Dominion’s operating activities increased by approximately $1.1 billion due to higher deferred fuel and gas cost recoveries, higher margins in its merchant generation and gas transmission operations, and a favorable impact from changes in customer receivables as a result of lower fuel and gas prices. The increase was partially offset by cash outflows related to collateral requirements and higher income tax payments as a result of higher estimated taxable income, which included a projected taxable gain from the planned sale of Peoples and Hope that was expected to close in 2009.
In 2009, net cash provided by Virginia Power’s operating activities increased by $735 million, primarily due to higher deferred fuel cost recoveries in its Virginia jurisdiction and a favorable change in customer receivables, partially offset by higher income tax payments. 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, 2009 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.
(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 36% 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 12% of the total net credit exposure.
(4) The five largest counterparty exposures, combined, for this category represented approximately 2% of the total net credit exposure.
Virginia Power’s exposure to potential concentrations of credit risk results primarily from sales to wholesale customers. Presented below is a summary of Virginia Power’s gross credit exposure as of December 31, 2009, 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.
(1) Designations as investment grade are based on minimum credit ratings assigned by Moody’s and Standard & Poor’s. The five largest counterparty exposures, combined, for this category represented approximately 58% of the total net credit exposure.
(2) The only two counterparty exposures, combined, for this category represented 18% of the total net credit exposure.
(3) The only two counterparty exposures, combined, for this category represented 21% of the total net credit exposure.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
Investing Cash Flows
In 2009, net cash used in Dominion’s investing activities increased by $205 million primarily due to an increase in capital expenditures related to its electric utility operations and the absence of the proceeds from the assignment of natural gas drilling rights, partially offset by reduced investments in and a distribution from its Fowler Ridge wind farm investment in connection with non-recourse project financing proceeds received in September 2009.
In 2009, net cash used in Virginia Power’s investing activities increased by $565 million, primarily reflecting an increase in capital expenditures for generation and transmission construction projects, including the Virginia City Hybrid Energy Center.
Financing Cash Flows and Liquidity
Dominion and Virginia Power rely on banks and 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 and, in the case of Virginia Power, approval by the Virginia Commission.
Each of the Companies 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 2009, net cash used in Dominion’s financing activities was $112 million as compared to net cash provided by financing activities of $598 million in 2008. This change is primarily due to higher dividend payments, and lower net debt issuances as a result of higher cash inflows from its operating activities, partially offset by increased proceeds from common stock issuances.
In 2009, net cash provided by Virginia Power’s financing activities decreased by $156 million, primarily due to lower net debt issuances as a result of higher cash flow from operations.
CREDIT FACILITIES AND SHORT-TERM DEBT
Dominion and Virginia Power use short-term debt to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. 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 under its commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit quality and the credit quality of Dominion’s counterparties.
Virginia Power’s short-term financing is supported by a five-year joint revolving credit facility in which it participates with Dominion. This credit facility is being used for working capital, as support for the combined commercial paper programs of the Companies and for other general corporate purposes. Dominion has two other facilities as detailed in the following table.
Commercial paper, bank loans, and letters of credit outstanding, as well as capacity available under credit facilities as of December 31, 2009 were as follows:
(1) This credit facility was entered into February 2006 and terminates in February 2011. 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 of letters of credit. At December 31, 2009, total outstanding commercial paper was $442 million, all of which were Virginia Power’s borrowings. At December 31, 2009, total outstanding letters of credit under the facility were $153 million, of which $104 million were issued on Virginia Power’s behalf.
(2) This credit facility was entered into August 2005 and terminates in August 2010. This facility can be used to support bank borrowings, the issuance of letters of credit and commercial paper.
(3) This facility was entered into December 2005 and terminates in December 2010. This credit facility can be used to support commercial paper and letter of credit issuances.
In addition to the credit facility commitments disclosed above, Virginia Power also has a five-year $120 million credit facility that terminates in February 2011, which supports certain of its tax-exempt financings.
Dominion and Virginia Power plan to replace their existing credit facilities during the second or third quarter of 2010. They expect to operate with credit facilities ranging from $3.0 to $3.5 billion. The Companies do not expect the reduction in the size of their credit facilities to negatively impact their ability to fund their operations.
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.
In February 2010, Dominion completed the sale of Peoples and netted after-tax proceeds of approximately $542 million, which it used to reduce debt.
LONG-TERM DEBT
During 2009, Dominion and Virginia Power issued the following long-term debt:
(1) Subject to extensions to no later than 2079.
Additionally, in May 2009, Dominion’s Brayton Point power station borrowed $50 million in connection with the Massachusetts Development Finance Agency Solid Waste Disposal Revenue Refunding Bonds Series 2009, which mature in 2042 and bear a coupon rate of 5.75% for the first ten years, after which they will bear interest at a market rate to be determined at that time, using a remarketing process. The proceeds were used to refinance certain qualifying improvements at Brayton Point.
In May 2009, Virginia Power borrowed $40 million in connection with the Economic Development Authority of the County of Chesterfield Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2023 and bear a coupon rate of 5.0%. The proceeds were used to refund the principal amount of the Industrial Development Authority of the County of Chesterfield Money Market MunicipalsTM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in October 2009.
In May 2009, Virginia Power borrowed $70 million in connection with the Economic Development Authority of York County, Virginia Pollution Control Refunding Revenue Bonds, Series 2009 A, which mature in 2033 and bear an initial coupon rate of 4.05% 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 were used to refund the principal amount of the Industrial Development Authority of York County, Virginia Money Market MunicipalsTM Pollution Control Revenue Bonds, Series 1985 that would otherwise have matured in July 2009.
In September 2009, Virginia Power borrowed $60 million 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 $60 million in bonds upon issuance in September 2009 with the intention of remarketing them to a third party at a later time. Proceeds will be used to finance qualifying facilities at the Virginia City Hybrid Energy Center. At December 31, 2009, these bonds had not been remarketed and thus are eliminated in consolidation, along with the investment.
Including the amounts discussed above, during 2009, Dominion and Virginia Power repaid $447 million and $126 million, respectively, of long-term debt and notes payable.
ISSUANCE OF COMMON STOCK
In January 2009, Dominion entered into sales agency agreements pursuant to which it may offer from time to time up to $400 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the New York Stock Exchange at market prices or in such other transactions as are agreed upon by the Company and the sales agents and in conformance with applicable securities laws.
During 2009, Dominion issued 14 million shares of common stock for cash proceeds of $456 million. Dominion issued 6.2 million shares through at-the-market issuances under its sales agency agreements and received cash proceeds of $191 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion has the ability to issue up to $207 million of stock under sales agency agreements. Dominion also issued 76,000 shares of its common stock to its officers and directors under a private placement program for aggregate consideration of approximately $2 million. The remainder of the shares issued and cash proceeds received during 2009 were through Dominion Direct®, employee savings plans and the exercise of employee stock options. Dominion anticipates a need for $400 million of external common equity in 2010. This need will be met by the issuance of common stock or in whole or in part by proceeds, if any in 2010, from the planned monetization of Dominion’s Marcellus Shale acreage.
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.
Additionally, in February 2009, Dominion issued approximately 1.6 million shares of common stock to an existing holder of its senior notes, in a privately negotiated transaction, in exchange for approximately $56 million of the principal of two series of its outstanding senior notes, which were retired. The transaction was exempt from registration pursuant to Section 3(a)(9) of the Securities Act and no commission or remuneration was paid in connection with the exchange.
In 2009, Virginia Power issued 31,877 shares of its common stock to Dominion reflecting the conversion of $1 billion of short-term demand note borrowings from Dominion to equity.
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.
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
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
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 December 2009, Fitch published a report that announced a global cross-sector change in its criteria for rating hybrid and other equity capital-like securities. 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 reflecting 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.
Credit ratings as of February 1, 2010 follow:
As of February 1, 2010, Fitch and Standard & Poor’s maintained a stable outlook for their respective ratings of Dominion and Virginia Power and Moody’s maintains a stable outlook on their ratings for Dominion and a positive outlook on their ratings for 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 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, 2009, the calculated total debt to total capital ratio, pursuant to the terms of the agreements, was as follows:
(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 fail to make payment on various debt obligations in excess of $35 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 agreement.
Dominion executed Replacement Capital Covenants (RCCs) in connection with its issuance of the following hybrid securities:

$300 million of 2006 Series A Enhanced Junior Subordinated Notes due 2066 (June 2006 hybrids)

$500 million of 2006 Series B Enhanced Junior Subordinated Notes due 2066 (September 2006 hybrids)

$685 million of 2009 Series A Enhanced Junior Subordinated Notes due 2064, subject to maturity extensions to no later than 2079 (June 2009 hybrids)
Under the terms of the RCCs, Dominion promises and 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 the respective RCC termination date, 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 at that time, as more fully described in the RCCs. The proceeds Dominion receives from the replacement offering, adjusted by a predetermined factor, must exceed the redemption or repurchase price.
At December 31, 2009, the termination dates and covered debt under the RCCs associated with Dominion’s hybrids are as follows:
(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, 2009, 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, 2009, 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, 2009.
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, 2009. 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 2010.
(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) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(4) 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.
(5) Includes capital, operations and maintenance commitments.
(6) 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, $186 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.
(7) Includes interest rate swap agreements.
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
(1) Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2) Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(3) 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, $97 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, $3.8 billion and $4.2 billion in 2010, 2011 and 2012, 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, purchases of nuclear fuel and expenditures to explore for and develop natural gas and oil properties.
Virginia Power’s planned capital expenditures are expected to total approximately $2.5 billion, $2.2 billion and $2.4 billion in 2010, 2011 and 2012, respectively. Virginia Power’s expenditures are expected to include construction and expansion of electric generation facilities, environmental upgrades and construction improvements and expansion of electric transmission and distribution assets.
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.
At December 31, 2009, Dominion had issued $261 million of guarantees to support third parties and equity method investees, primarily reflecting guarantees issued to support the NedPower and Fowler Ridge wind farm joint ventures. See Note 23 to the Consolidated Financial Statements for further discussion of these guarantees.
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; 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 $252 million, $205 million, and $181 million of expenses (including depreciation) during 2009, 2008, and 2007 respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $268 million and $274 million in 2010 and 2011, respectively. In addition, capital expenditures related to environmental controls were $266 million, $254 million, and $293 million for 2009, 2008, and 2007, respectively. These expenditures are expected to be approximately $383 million and $322 million for 2010 and 2011, respectively.
Virginia Power incurred approximately $134 million, $125 million, and $121 million of expenses (including depreciation) during 2009, 2008, and 2007, respectively, in connection with environmental protection and monitoring activities and expects these expenses to be approximately $153 million and $150 million in 2010 and 2011, respectively. In addition, capital expenditures related to environmental controls were $109 million, $116 million, and $189 million for 2009, 2008 and 2007, respectively. These expenditures are expected to be approximately $102 million and $54 million for 2010 and 2011, respectively.
FUTURE ENVIRONMENTAL REGULATIONS
There has already been federal legislative proposals and regulatory action regarding the regulation of GHG emissions. Dominion and Virginia Power expect that there may be federal legislation or regulatory action regarding compliance with more stringent air emission standards, regarding coal combustion byproducts, and regarding regulation of cooling water intake structures and discharges in the future. With respect to GHG emissions, the outcome in terms of specific requirements and timing is uncertain but may include a GHG emissions cap-and-trade program or a carbon tax for electric generators and natural gas businesses or regulation of GHGs under the CAA. With respect to emission reductions, specific requirements will depend on how the EPA and/or states replace CAMR and the outcome of the EPA’s response to the CAIR remand. With respect to cooling water intakes and discharges, the Companies expect future federal regulation on cooling water intake structures and more focus by EPA and state regulatory authorities on thermal discharge issues. With respect to coal combustion byproducts, Dominion and Virginia Power expect federal regulation of coal combustion byproduct handling and disposal practices. If any of these new proposals are adopted, additional significant expenditures may be required.
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 production and 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 and 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 electricity, 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 $150 million and $236 million as of December 31, 2009 and 2008, respectively. The decline largely reflects settlements of commodity derivative positions existing as of the beginning of 2009. A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $11 million and $5 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes as of December 31, 2009 and 2008, respectively. The increase largely reflects a decrease in commodity prices as well as increased commodity derivative activity.
A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $3 million and $23 million in the fair value of Virginia Power’s non-trading commodity-based financial derivatives as of December 31, 2009 and 2008, respectively. The decline largely reflects settlements of
Management’s Discussion and Analysis of Financial Condition and Results of Operations, Continued
commodity derivative positions existing as of the beginning of 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 such 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 outstanding for Dominion at December 31, 2009 and 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of approximately $2 million and $4 million, respectively. For financial instruments outstanding for Virginia Power at December 31, 2009 and 2008, a hypothetical 10% increase in market interest rates would have resulted in a decrease in annual earnings of less than $1 million and approximately $2 million, respectively.
Additionally, Dominion and Virginia Power may 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. Dominion and Virginia Power did not have a significant amount of these interest rate derivatives outstanding at December 31, 2008.
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 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.
Following the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations in April 2007, gains or losses on those decommissioning trust investments are deferred as regulatory liabilities.
Dominion recognized net realized gains (including investment income) on nuclear decommissioning trust investments of $29 million in 2009. Dominion recognized net realized losses (net of
investment income) on nuclear decommissioning trust investments of $192 million in 2008. 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 2009, Dominion recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $349 million. In 2008, Dominion recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $451 million.
Virginia Power recognized net realized losses (net of investment income) on nuclear decommissioning trust investments of $3 million and $57 million in 2009 and 2008, 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 2009, Virginia Power recorded, in AOCI and regulatory liabilities, a net increase in unrealized gains on these investments of $149 million. In 2008, Virginia Power recorded, in AOCI and regulatory liabilities, a reduction in unrealized gains on these investments of $233 million.
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 $777 million in 2009 and negative $1.4 billion in 2008, versus expected returns of $462 million and $484 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, investment-related declines in these trusts, such as those experienced during 2008, 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. As of December 31, 2009 and 2008, 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 $12 million for pension benefits and $2 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 risk management policies of all subsidiaries, including Virginia Power. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on these credit policies and Dominion’s and Virginia Power’s December 31, 2009 provision for credit losses, management believes that it is unlikely that a material adverse effect on Dominion’s or Virginia Power’s financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.
Item 8. Financial Statements and Supplementary Data
Page No.
Dominion Resources, Inc.
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheets at December 31, 2009 and 2008
Consolidated Statements of Common Shareholders’ Equity at December 31, 2009, 2008 and 2007 and for the years then ended
Consolidated Statements of Comprehensive Income at December 31, 2009, 2008 and 2007 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Virginia Electric and Power Company
Report of Independent Registered Public Accounting Firm
Consolidated Statements of Income for the years ended December 31, 2009, 2008 and 2007
Consolidated Balance Sheets at December 31, 2009 and 2008
Consolidated Statements of Common Shareholder’s Equity at December 31, 2009, 2008 and 2007 and for the years then ended
Consolidated Statements of Comprehensive Income at December 31, 2009, 2008 and 2007 and for the years then ended
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007
Combined Notes to Consolidated Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Dominion Resources, Inc.
Richmond, Virginia
We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (“Dominion”) as of December 31, 2009 and 2008, 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, 2009. 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.
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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Dominion Resources, Inc. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, Dominion changed its methods of accounting to adopt new accounting standards for the impairment framework for oil and gas properties in 2009 and fair value measurements in 2008.
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, 2009, 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 26, 2010 expressed an unqualified opinion on Dominion’s internal control over financial reporting.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2010
Dominion Resources, Inc.
Consolidated Statements of Income
(1) Net of income tax expense (benefit) of ($3) million and $115 million in 2008 and 2007, respectively. The 2007 expense includes $76 million and $56 million for U.S. federal and Canadian taxes, respectively, related to the gain on the sale of the Canadian E&P operations.
(2) Reflects a $259 million ($158 million after-tax) extraordinary charge in connection with the reapplication of accounting guidance for cost-based regulation, to the Virginia jurisdiction of Virginia Power’s generation operations.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Balance Sheets
(1) 1 billion shares authorized; 599 million shares and 583 million shares outstanding at December 31, 2009 and 2008, respectively.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Common Shareholders’ Equity
(1) Includes net income attributable to Dominion before deduction for subsidiary preferred dividends.
(2) Includes $256 million of accrued dividends due to the early declaration of the first quarter 2009 common dividend in December 2008.
(3) See Note 3 for additional information.
(4) Includes at-the-market issuances and a debt for common stock exchange. See Note 20 for additional information.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Comprehensive Income
(1) Other comprehensive income for the year ended December 31, 2009 excludes a $20 million ($12 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
Dominion Resources, Inc.
Consolidated Statements of Cash Flows
(1) As discussed in Note 3, 2008 and 2007 amounts have been recast due to Dominion’s adoption of new accounting guidance for noncontrolling interests.
(2) 2009, 2008 and 2007 amounts include $2 million, $5 million and $4 million, respectively, of cash classified as held for sale in Dominion’s Consolidated Balance Sheets.
The accompanying notes are an integral part of Dominion’s Consolidated Financial Statements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Virginia Electric and Power Company
Richmond, Virginia
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, 2009 and 2008, 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, 2009. 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, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 3 to the consolidated financial statements, Virginia Power changed its methods of accounting to adopt a new accounting standard for fair value measurements in 2008.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2010
Virginia Electric and Power Company
Consolidated Statements of Income
(1) Reflects a $259 million ($158 million after-tax) extraordinary charge in connection with the reapplication of accounting guidance for cost-based regulation, to the Virginia jurisdiction of Virginia Power’s generation operations.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Balance Sheets
(1) 300,000 shares authorized; 241,710 shares and 209,833 shares outstanding at December 31, 2009 and 2008, respectively.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Common Shareholder’s Equity
(1) See Note 3 for additional information.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Comprehensive Income
(1) Other comprehensive income for the year ended December 31, 2009 excludes a $3 million ($2 million after-tax) adjustment to AOCI representing the cumulative effect of the change in accounting principle related to the recognition and presentation of other-than-temporary impairments.
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Virginia Electric and Power Company
Consolidated Statements of Cash Flows
The accompanying notes are an integral part of Virginia Power’s Consolidated Financial Statements.
Combined Notes to 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 northeastern 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, Pennsylvania and West Virginia. As discussed in Note 4, Dominion completed the sale of its Pennsylvania gas distribution operations in February 2010. Dominion’s nonregulated operations include merchant generation, energy marketing and price risk management activities, retail energy marketing operations and natural gas and oil exploration and production in the Appalachian basin of the U.S.
Dominion manages its daily operations through three primary operating segments: DVP, Dominion Generation and Dominion Energy. In addition, Dominion reports a Corporate and Other segment that includes its corporate, service company and other functions and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 4. Corporate and Other also includes specific items attributable to Dominion’s operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or in allocating resources among the segments. Prior to the fourth quarter of 2009, Hope was included in Dominion’s Corporate and Other segment and its assets and liabilities were classified as held for sale. During the fourth quarter of 2009, following Dominion’s decision to retain this subsidiary, Hope was transferred to the Dominion Energy operating segment and its assets and liabilities were reclassified from held for sale.
Virginia Power manages its daily operations through two primary operating segments: DVP and Dominion Generation. It also reports a Corporate and Other segment that primarily includes specific items attributable to its operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments. See Note 27 for further discussion of Dominion’s and Virginia Power’s operating segments.
The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one or more of Dominion Resources, Inc.’s consolidated subsidiaries (other than Virginia Power) or operating segments, or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.
The term “Virginia Power” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Virginia Electric and Power Company, one or more of its consolidated subsidiaries or operating segments or the entirety of Virginia Power and its consolidated subsidiaries.
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 and instruments at fair value. See Note 7 for further information on fair value measurements.
Certain amounts in the 2008 and 2007 Consolidated Financial Statements and footnotes have been recast to conform to the 2009 presentation.
Amounts disclosed for Dominion are inclusive of Virginia Power, where applicable.
Accounting for the Effects of Certain Types of Regulation
In March 1999, Virginia Power discontinued the application of accounting guidance for cost-based regulation for the majority of its generation operations upon the enactment of deregulation legislation in Virginia. Virginia Power’s electric utility transmission and distribution operations continued to apply this guidance since they remained subject to cost-of-service rate regulation.
In April 2007, the Virginia General Assembly passed legislation that returned the Virginia jurisdiction of Virginia Power’s generation operations to cost-of-service rate regulation. As a result, Virginia Power reapplied accounting guidance for cost-based regulation to those operations in April 2007, when the legislation was enacted. In connection with the reapplication of this guidance to these operations, Virginia Power prospectively changed certain of its accounting policies to those used by cost-of-service rate-regulated entities. Other than the items discussed below, the overall impact of these changes was not material to Virginia Power’s results of operations or financial condition in 2007. These policy changes are discussed further in Derivative Instruments, Investments, Property, Plant and Equipment and Asset Retirement Obligations.
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, 2009 and 2008 included $409 million and $401 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, 2009 and 2008 included $355 million and $341 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. Sales require delivery of the product to the purchaser, passage of title and probability of collection of purchaser amounts owed. Revenue from sales of gas production includes the sale of Company produced gas 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.
For electric fuel and purchased energy expenses, effective January 1, 2004, the fuel factor provisions for Virginia Power’s Virginia retail customers were fixed until July 1, 2007. Beginning July 1, 2007, the fuel factor has been adjusted annually as dis -
cussed under Electric Regulation in Virginia in Note 14. 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. Dominion also filed federal and provincial income tax returns for certain former subsidiaries in Canada. 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 the majority of Dominion’s and Virginia Power’s unrecognized tax benefits, the ultimate deductibility is highly certain, but 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 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 and current payables are included in accrued interest, payroll and taxes, 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 2009, 2008 and 2007, Dominion recognized a reduction in interest expense of
Combined Notes to Consolidated Financial Statements, Continued
$19 million and a reduction in penalties of $2 million, less than $1 million of interest expense and no penalties, and a reduction in interest expense of $19 million and no penalties, respectively. Dominion had accrued interest receivable of $26 million and interest and penalties payable of $4 million at December 31, 2009, and interest receivable of $2 million and interest and penalties payable of $5 million at December 31, 2008.
Virginia Power’s interest and penalties were immaterial in 2009, 2008 and 2007.
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. At December 31, 2008, Virginia Power’s Consolidated Balance Sheet included $3 million of prepaid state income taxes, $6 million of current federal and state income taxes payable, and $106 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, 2009 and 2008, Dominion’s accounts payable included $55 million and $60 million, respectively, of checks outstanding but not yet presented for payment. At December 31, 2009 and 2008, Virginia Power’s accounts payable included $22 million and $23 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, except 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 $149
million and margin liabilities of $114 million, and Virginia Power had margin assets of $4 million and did not have any margin liabilities associated with cash collateral at December 31, 2009. Dominion had margin assets of $168 million and margin liabilities of $406 million, and Virginia Power had margin assets of $18 million and margin liabilities of $4 million associated with cash collateral at December 31, 2008.
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.
Following the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations, for jurisdictions subject to cost-based regulation, changes in the fair value of derivative instruments result in the recognition of regulatory assets or regulatory liabilities. 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 relationship 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 portion of Dominion’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. A portion of Virginia Power’s hedge strategies represents cash flow hedges of the variable price risk associated with the purchase of electricity, natural gas and other energy-related products. The Companies also use foreign currency forward and option 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.
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 2009, 2008 and 2007, Dominion capitalized interest costs and AFUDC to property, plant and equipment of $76 million, $88 million, and $102 million, respectively. In 2009, 2008 and 2007, Virginia Power capitalized interest costs and AFUDC to property, plant and equipment of $47 million, $21 million, and $27 million, respectively. Upon reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations in April 2007, Virginia Power discontinued capitalizing interest on generation-related construction projects since the Virginia Commission previously allowed for current recovery of construction financing costs. 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 2009, 2008 and 2007, Virginia Power recorded $34
million, $18 million and $1 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 effective April 2007, and certain Dominion natural gas property, the undepreciated cost of such property, less salvage value, is 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 and utility generation property prior to the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations in April 2007, 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:
(1) In October 2007, depreciation rates for utility generation assets were revised to reflect the results of a new depreciation study, which incorporates the property, plant and equipment accounting policy changes that were made upon the reapplication of accounting guidance for cost-based regulation, as well as updates to other assumptions. This change increased annual depreciation expense by approximately $54 million ($33 million after-tax).
Dominion’s nonutility property, plant and equipment, excluding E&P properties, is depreciated using the straight-line method over the following estimated useful lives:
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.
Combined Notes to Consolidated Financial Statements, Continued
Dominion follows the full cost method of accounting for gas and oil E&P activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. These capitalized costs are subject to a quarterly ceiling test. Under the ceiling test, amounts capitalized are limited to the present value of estimated future net revenues to be derived from the anticipated production of proved gas and oil reserves, discounted at 10%, using trailing twelve month average natural gas and oil prices adjusted for cash flow hedges in place. Prior to adoption of the SEC’s Final Rule, Modernization of Oil and Gas Reporting effective December 31, 2009, period-end gas and oil prices were used when performing the full cost ceiling test calculation; however, subsequent commodity price increases could be utilized to reduce or eliminate any impairment in accordance with SEC guidelines. If net capitalized costs exceed the ceiling test at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period. Approximately 3% of Dominion’s anticipated production is hedged by qualifying cash flow hedges, for which hedge-adjusted prices were used to calculate estimated future net revenue. Using trailing twelve month average prices, adjusted for cash flow hedges in place, there was no ceiling test impairment at December 31, 2009. Excluding the effects of hedge-adjusted prices in calculating the ceiling test limitation would have resulted in an approximately $41 million ($25 million after-tax) ceiling test impairment.
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). Future cash flows associated with settling AROs that have been accrued in Dominion’s Consolidated Balance Sheets are excluded from Dominion’s calculations under the full cost ceiling test. Decreases in commodity prices, as well as changes in production levels, reserve estimates, future development costs, and lifting costs and other factors could result in future ceiling test impairments.
Depletion of Dominion’s gas and oil producing properties is computed using the units-of-production method. Under the full cost method, the depletable base of costs subject to depletion also includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. The costs of investments in unproved properties including associated exploration-related costs are initially excluded from the depletable base. Until the properties are evaluated, a ratable portion of the capitalized costs is periodically reclassified to the depletable base, determined on a property by property basis, over terms of underlying leases. Once a property has been evaluated, any remaining capitalized costs are then transferred to the depletable base. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a cost pool. In 2007, Dominion recognized gains from the sales of its Canadian and U.S. non-Appalachian E&P businesses 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, NOX and CO2. SO2 and NOX emissions allowances are issued to Dominion and Virginia Power by the EPA. 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. Allowances issued directly to Dominion or Virginia Power by the EPA are carried 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 or as consumed.
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 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.
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. With the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of its generation operations in April 2007, Virginia Power now 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. Previously, Virginia Power reported such expense in other operations and maintenance expense in the Consolidated Statements of Income. 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. Upon reapplication of accounting guidance for cost-based regulation in April 2007 for the Virginia jurisdiction of Virginia Power’s generation operations, net realized and unrealized gains and losses (including any other-than-temporary impairments) on investments held in its 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 and Rabbi 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
Combined Notes to Consolidated Financial Statements, Continued
the debt security before recovery of its fair value up to its cost basis. For any debt security that 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. They evaluate credit losses primarily by considering the credit ratings of the issuer, prior instances of non-performance by the issuer and other factors. For investments in Virginia Power’s nuclear decommissioning trusts, net realized and unrealized gains and losses on debt securities (including any other-than-temporary impairments) continue to be recorded to a regulatory liability for certain jurisdictions subject to cost-based regulation.

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 and rabbi 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 and rabbi 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 local gas distribution operations is valued using the LIFO method. Under the LIFO method, those inventories were valued at $30 million and $8 million at December 31, 2009 and 2008, respectively. The increase in inventory from 2008 to 2009 reflects the reclassification of Hope’s inventory from assets held for sale due to Dominion’s decision to retain this subsidiary. Based on the average price of gas purchased during 2009 and 2008, the cost of replacing the current portion of stored gas inventory exceeded the amount stated on a LIFO basis by approximately $172 million and $208 million, respectively. Stored gas inventory held by certain nonregulated gas operations is valued using the weighted-average cost method.
Gas Imbalances
TRANSPORTATION
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.
PRODUCTION
Dominion uses the sales method of accounting for gas imbalances related to natural gas production. An imbalance is created when
Company volumes of gas sold pertaining to a property do not equate to the volumes to which Dominion is entitled based on its interest in the property. A liability is recognized when Dominion’s excess sales over entitled volumes exceeds its net remaining property reserves.
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
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 the amortized cost bases are recovered.
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. Going forward, Dominion will be less likely to experience a ceiling test impairment based solely on a sudden decrease in gas and oil prices.
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.
In February 2008, the FASB amended the fair value measurements guidance to exclude leasing transactions. However, the exclusion does not apply to fair value measurements of assets and liabilities recorded as a result of a lease transaction but measured pursuant to other pronouncements within the scope of the fair value measurements guidance.
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 guidance resulted in an immaterial amount recognized through a cumulative effect of accounting change adjustment to retained earnings as of January 1, 2008.
ACCOUNTING FOR UNCERTAINTY IN INCOME TAXES
Effective January 1, 2007, Dominion and Virginia Power adopted new FASB guidance for accounting for uncertainty in income taxes. As a result of the implementation of this guidance, Dominion recorded a $58 million charge and Virginia Power recorded a $5 million benefit to beginning retained earnings, representing the cumulative effect of the change in accounting principle. At January 1, 2007, Dominion and Virginia Power had unrecognized tax benefits of $625 million and $225 million, respectively. For the majority of unrecognized tax benefits, the ultimate deductibility is highly certain, but there is uncertainty about the timing of such deductibility.
NOTE 4. DISPOSITIONS
Sale of Non-Appalachian Natural Gas and Oil E&P Operations and Assets
In 2007, Dominion completed the sale of its non-Appalachian natural gas and oil E&P operations and received approximately $13.3 billion for its U.S. non-Appalachian E&P operations and approximately $624 million for its Canadian E&P operations.
Due to the sale of Dominion’s entire Canadian cost pool, the results of operations for Dominion’s Canadian E&P business are reported as discontinued operations in the Consolidated Statements of Income. The results of operations for Dominion’s U.S. non-Appalachian E&P business were not reported as discontinued operations in the Consolidated Statements of Income since Dominion did not sell its entire U.S. cost pool, which includes the retained Appalachian assets.
Dominion used most of the after-tax proceeds from these dispositions to reduce outstanding debt and repurchase shares of its common stock.
CANADIAN OPERATIONS
The sale of Dominion’s Canadian E&P operations resulted in an after-tax gain of $59 million ($0.08 per share).
The following table presents selected information regarding the results of operations of Dominion’s Canadian E&P operations, which are reported as discontinued operations in the Consolidated Statements of Income:
(1) Amount reflects the net effect of contractual post-closing adjustments to the sale.
(2) Amount includes a pre-tax gain of $191 million recognized on the sale.
Combined Notes to Consolidated Financial Statements, Continued
COSTS ASSOCIATED WITH DISPOSAL OF NON-APPALACHIAN E&P OPERATIONS
The sales of Dominion’s U.S. non-Appalachian E&P operations resulted in the discontinuance of hedge accounting for certain cash flow hedges since it became probable that the forecasted sales of gas and oil would not occur. In connection with the discontinuance of hedge accounting for these contracts, Dominion recognized charges, recorded in operating revenue in the Consolidated Statement of Income, predominantly reflecting the reclassification of losses from AOCI to earnings and subsequent changes in fair value of these contracts of $541 million ($342 million after-tax) in 2007. Dominion terminated these gas and oil derivatives subsequent to the disposal of the non-Appalachian E&P business. Dominion recognized a similar charge of $15 million ($9 million after-tax) in 2007 related to its Canadian operations, which is reflected in discontinued operations in the Consolidated Statement of Income.
During 2007, Dominion also recorded a charge in operating revenue in the Consolidated Statement of Income of approximately $171 million ($108 million after-tax) for the recognition of certain forward gas contracts that previously qualified for the normal purchase and sales exemption. The $171 million charge included $139 million associated with VPP agreements to which Dominion was a party. Dominion paid $250 million to terminate the VPP agreements and retained the VPP royalty interests formerly associated with these agreements.
Additionally, Dominion recognized expenses for employee severance, retention and other costs of $91 million ($56 million after-tax) in 2007, related to the sale of its U.S. non-Appalachian E&P business, which are reflected in other operations and maintenance expense in the Consolidated Statement of Income. Dominion also recognized expenses for employee severance, retention, legal, investment banking and other costs of $30 million ($18 million after-tax) in 2007 related to the sale of its Canadian E&P operations, which are reflected in discontinued operations in the Consolidated Statement of Income.
Dominion recognized a gain of approximately $3.6 billion ($2.1 billion after-tax) from the disposition of its U.S. non-Appalachian E&P operations. This gain is net of expenses related to the disposition plan for transaction costs, including audit, legal, investment banking and other costs of $48 million ($30 million after-tax), but excludes severance and retention costs and costs associated with the discontinuance of hedge accounting and recognition of forward gas contracts. In 2008, the net effect of contractual post-closing adjustments resulted in a $42 million ($26 million after-tax) reduction to the gain recognized in 2007. The total impact on net income from the sale of Dominion’s Canadian and U.S. non-Appalachian E&P operations was a benefit of $1.5 billion for 2007. This benefit is net of expenses for transaction costs, severance and retention costs, costs associated with the discontinuance of hedge accounting and recognition of forward gas contracts, and costs associated with Dominion’s debt tender offer completed in July 2007 using a portion of the proceeds received from the sale as discussed below.
Dominion completed a debt tender offer repurchasing $2.5 billion of its debt securities in July 2007. Dominion recognized charges of $242 million ($148 million after-tax) primarily in connection with the early redemption of this debt. Of this amount, $234 million ($143 million after-tax) was recorded in
interest and related charges in its Consolidated Statement of Income.
Disposition of Partially Completed Generation Facility
In September 2007, Dominion completed the sale of Dresden to AEP Generating Company for $85 million. During 2007, Dominion recorded a $387 million ($252 million after-tax) impairment charge in other operations and maintenance expense to reduce Dresden’s carrying amount to its estimated fair value based on AEP Generating Company’s purchase price.
Sale of Certain DCI Operations
In May 2007, Dominion committed to a plan to dispose of certain DCI operations including substantially all of the assets of Gichner, LLC, all of the issued and outstanding shares of the capital stock of Gichner, Inc. (an affiliate of Gichner, LLC), as well as all of the membership interests in Dallastown.
The consideration to be received indicated that the goodwill associated with these operations was impaired and Dominion recorded a goodwill impairment charge of $8 million in other operations and maintenance expense in the Consolidated Statement of Income. In August 2007, Dominion completed the sale of Gichner, LLC and Dallastown for approximately $30 million. The sale resulted in an after-tax loss of $4 million, which included $10 million of goodwill.
For the year ended December 31, 2007, operating revenue and loss before income taxes for Gichner, LLC and Dallastown were $29 million and $7 million, respectively, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income.
Sale of Merchant Generation Facilities
In 2007, Dominion sold three Peaker facilities for net cash proceeds of $254 million. The sale resulted in a $24 million after-tax loss ($0.03 per share). The Peaker facilities included:

Armstrong, a 625 MW station in Shelocta, Pennsylvania;

Troy, a 600 MW station in Luckey, Ohio; and

Pleasants, a 313 MW station in St. Mary’s, West Virginia.
For the year ended December 31, 2007, operating revenue and loss before income taxes for the Peaker facilities were $5 million and $31 million, respectively, which are reported as discontinued operations in Dominion’s Consolidated Statements of Income.
Sale of Peoples
On March 1, 2006, Dominion entered into an agreement with Equitable to sell two of its wholly-owned regulated gas distribution subsidiaries, Peoples and Hope. Peoples serves approximately 358,000 customer accounts in Pennsylvania and Hope serves approximately 114,000 customer accounts in West Virginia. This sale was subject to regulatory approvals in the states in which the companies operate, as well as antitrust clearance under the HSR Act. In January 2008, Dominion and Equitable announced the termination of the agreement for the sale of Peoples and Hope, primarily due to the continued delay in achieving final regulatory approval. Dominion continued to seek other offers for the purchase of these utilities.
In July 2008, Dominion entered into an agreement with an indirect subsidiary of BBIFNA to sell Peoples and Hope. In May 2009, following a change in ownership of the general partner of
BBIFNA and other related transactions, BBIFNA was renamed “SteelRiver Infrastructure Fund North America LP”. The sale of Peoples and Hope to the SteelRiver Buyer, an indirect subsidiary of the SteelRiver Fund, was expected to close in 2009, subject to state regulatory approvals in Pennsylvania and West Virginia. In November 2009, the Pennsylvania Commission approved the settlement entered into among Dominion, Peoples, the SteelRiver Buyer and two of the active intervenors in the Peoples sale proceeding, thereby approving the sale of Peoples to the SteelRiver Buyer. In December 2009, the West Virginia Commission denied the application for the sale of Hope. Dominion decided to retain Hope, but continue with the sale of Peoples. The sales price for Peoples was approximately $780 million, subject to changes in working capital, capital expenditures and affiliated borrowings. In February 2010, Dominion completed the sale of Peoples and netted after-tax proceeds of approximately $542 million. Dominion expects to recognize an after-tax loss of approximately $140 million (including $79 million of goodwill), as well as after-tax expenses of approximately $50 million, including transaction and benefit-related costs, in connection with the sale of Peoples.
The carrying amounts of the major classes of assets and liabilities classified as held for sale in Dominion’s Consolidated Balance Sheets are as follows:
The results of operations of a component of an entity that has been disposed of or is classified as held for sale are required to be reported in discontinued operations if both of the following conditions are met: (a) the operations and cash flows of the components have been (or will be) eliminated from the ongoing operations of the entity as a result of the disposal transaction and (b) the entity will not have any significant continuing involvement in the operations of the component after the disposal transaction. While Dominion does not expect to have significant continuing involvement with Peoples after its disposal, it does
expect to have continuing cash flows related primarily to the sale to Peoples of natural gas production from Dominion’s Appalachian E&P operations, as well as natural gas transportation and storage services provided to Peoples by Dominion’s gas transmission operations. Due to these expected significant continuing cash flows, the results of Peoples have not been reported as discontinued operations in the Consolidated Statements of Income. Dominion will continue to assess the level of its involvement and continuing cash flows with Peoples for one year after the date of sale, and if circumstances change, Dominion may be required to reclassify the results of Peoples as discontinued operations in its Consolidated Statements of Income.
The following table presents selected information regarding the results of operations of Peoples:
(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.
NOTE 5. OPERATING REVENUE
Dominion’s and Virginia Power’s operating revenue consists of the following:
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.
The American Recovery and Reinvestment Act of 2009 includes provisions to stimulate economic growth, including
Combined Notes to Consolidated Financial Statements, Continued
incentives for increased capital investment by businesses and incentives to promote renewable energy. Under the act, Dominion and Virginia Power have claimed bonus tax depreciation in 2009 for qualifying expenditures, which reduced their income taxes payable and increased deferred tax liabilities.
Details of income tax expense for continuing operations including noncontrolling interests were as follows:
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:
In 2008, Dominion’s effective tax rate reflected the reversal of $136 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 and Hope. In 2006, based on the intended form of the sale of Peoples and Hope to Equitable, 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 and Equitable 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. As discussed in Note 4, Dominion executed a new agreement in July 2008 to sell Peoples and Hope, but decided in December 2009 to sell only Peoples. Dominion will determine its taxable gain by reference to the basis in the subsidiary’s underlying assets.
In 2007, Dominion’s effective tax rate reflected the effects of the sale of its U.S. non-Appalachian E&P operations, including the impact of goodwill, not deductible for tax purposes, that reduced the book gain on sale. In addition, Dominion recognized a tax benefit from eliminating $126 million of valuation allowances on deferred tax assets that relate to federal and state loss carryforwards, which have been utilized to partially offset taxes otherwise payable on the gain from the sale.
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amount 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:
At December 31, 2009, 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 $1 billion that expire if unutilized during the period 2011 through 2028. A valuation allowance on $725 million of these carryforwards has been established; and

State minimum tax credits of $93 million that do not expire.
There were no loss or credit carryforwards for Virginia Power at December 31, 2009.
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 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:
Certain unrecognized tax benefits, or portions thereof, if recognized, would affect the effective tax rate. Changes in these unrecognized tax benefits resulted 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 statute of limitations. For Dominion and its subsidiaries, these unrecognized tax benefits were $95 million, $121 million and $101 million at December 31, 2009, 2008 and 2007, respectively. For Dominion, the change in these unrecognized tax benefits decreased income tax expense by $26 million in 2009 and increased tax expense by $25 million in both 2008 and 2007. For Virginia Power, these unrecognized tax benefits were $14 million, $21 million and $8 million at December 31, 2009, 2008 and 2007, respectively. For Virginia Power, the change in these unrecognized tax benefits decreased income tax expense by $7 million in 2009 and increased tax expense by $13 million and $3 million in 2008 and 2007, respectively.
However, for the majority of Dominion’s and Virginia Power’s unrecognized tax benefits, the ultimate deductibility is highly certain, but 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. However, with the realization of gains from the non-Appalachian E&P sales, these prior year amounts would have become fully deductible for federal income tax purposes in 2007. Pending resolution of these uncertainties, interest is being 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 2002, except that the right to pursue refunds related to certain deductions has been reserved for the years 1995 through 2001.
In 2009, the U.S. Congressional Joint Committee on Taxation 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 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.
In 2007, the IRS completed its examination of Dominion’s 2002 and 2003 consolidated returns and the 2002 and 2003 returns of certain affiliated partnerships. Dominion filed protests for certain proposed adjustments with the Appellate Division of the IRS in July and October 2007, and is currently engaged in settlement negotiations regarding those adjustments. In addition, the IRS completed its audit of tax years 2004 and 2005 in June 2009. Dominion filed protests for certain proposed adjustments with the Appellate Division of the IRS in July 2009.
With Dominion’s appeals of assessments received from tax authorities, including amounts subject to settlement negotiations with the Appellate Division of the IRS, it is reasonably possible that Dominion’s unrecognized tax benefits could decrease in 2010 by up to $30 million, including a decrease of up to $25 million for Virginia Power. In addition, Dominion’s unrecognized tax benefits could be reduced during 2010 by $18 million, including $6 million for Virginia Power, to recognize prior period amounts becoming otherwise deductible in the current period. Since the uncertainty for the majority of these unrecognized tax benefits involves only the timing of the deductions, Dominion anticipates that the impact on earnings will be limited to revisions of its accrual for interest on tax underpayments and overpayments.
Otherwise, with regard to tax years 2004 through 2009, Dominion cannot estimate the range of reasonably possible changes to unrecognized tax benefits that may occur in 2010.
Combined Notes to Consolidated Financial Statements, Continued
For each of the major states in which Dominion operates, the earliest tax year remaining open for examination is as follows:
(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.
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 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 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, and commingled 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 investments in partnerships 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 applicable 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 also categorized as Level 3. For the same illiquidity reason, natural gas peaking options at non-Henry Hub locations are valued using Henry Hub (NYMEX natural gas delivery point) volatilities, which may or may not be identical to the volatilities at transacted locations, and are therefore not considered to be observable inputs. 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. Investments in partnerships 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 net asset value based on the proportionate share held of the partnership’s 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.
At December 31, 2009, Dominion’s and Virginia Power’s net balance of commodity derivatives categorized as Level 3 fair value measurements was a net liability of $66 million and $10 million, respectively. A hypothetical 10% increase in commodity prices would increase Dominion’s and Virginia Power’s net liability by $32 million and $2 million, respectively. A hypothetical 10% decrease in commodity prices would decrease Dominion’s and Virginia Power’s net liability by $33 million and $2 million, respectively.
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.
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 very 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:
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.
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.
Combined Notes to Consolidated Financial Statements, Continued
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:
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:
(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:
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:
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:
(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, 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. Dominion’s and Virginia Power’s financial instruments’ carrying amounts and fair values are as follows:
(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, 2009, and 2008, includes the valuation of certain fair value hedges associated with Dominion’s fixed rate debt, of approximately $23 million and $15 million, respectively, and $1 million in 2008 associated with Virginia Power’s fixed rate debt.
(3) Includes issuance expenses of $2 million at December 31, 2009 and 2008.
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 marketed and purchased, as well as currency exchange and interest rate risks of their business operations. They 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 regulation, changes in the fair value of derivatives designated as hedges 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, 2009. 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.
(1) Includes options.
(2) Includes NGLs and oil.
Combined Notes to Consolidated Financial Statements, Continued
Selected information about Dominion’s hedge accounting activities follows:
(1) 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 Statements of Income.
(2) For 2007, represents hedge ineffectiveness, primarily due to changes in the fair value differential between the delivery location and commodity specifications of derivatives held by Dominion’s E&P operations and the delivery location and commodity specifications of its forecasted gas and oil sales.
(3) Amounts excluded from the measurement of ineffectiveness related to cash flow hedges for the years ended December 31, 2009, 2008 and 2007 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 Statements of Income.
See Note 4 for a discussion of the discontinuance of hedge accounting for non-Appalachian E&P gas and oil derivatives during 2007.
In 2007, as a result of the termination of the long-term power sales agreement associated with State Line, Dominion discontinued applying the normal purchase and normal sale exception to this agreement and recorded a $231 million ($137 million after-tax) charge in operating revenue in its Consolidated Statement of Income. During the fourth quarter of 2007, Dominion paid approximately $229 million primarily in exchange for the termination of the power sales agreement, acquisition of coal inventory and assignment of certain coal supply, transportation and railcar lease contracts.
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, 2009:
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, interest rates and foreign exchange rates.
Fair Value and Gains and Losses on Derivative Instruments
The following table presents the fair values of Dominion’s derivatives at December 31, 2009 and where they are presented in its Consolidated Balance Sheet:
(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 Sheet and Statement of Income at December 31, 2009:
(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)
(millions)
Derivative Type and Location of Gains (Losses)
Commodity
Operating revenue
$105
Purchased gas
(66)
Electric fuel and other energy-related purchases
(163)
Total
$(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.
VIRGINIA POWER
The following table presents the volume of Virginia Power’s derivative activity at December 31, 2009. 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
6.0
-
Basis
3.0
-
Electricity (MWh):
Fixed price
488,800
-
FTRs
45,055,471
3,541,577
Capacity (MW)
462,462
364,200
Interest rate
$850,000,000
$75,000,000
Foreign currency (euros)
24,665,541
-
For the years ended December 31, 2009, 2008 and 2007, 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, 2009:
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, interest rates and foreign exchange rates.
Combined Notes to Consolidated Financial Statements, Continued
Fair Value and Gains and Losses on Derivative Instruments
The following table presents the fair values of Virginia Power’s derivatives at December 31, 2009 and where they are presented on its Consolidated Balance Sheet:
(1) Noncurrent derivative assets are presented in other deferred charges and other assets in Virginia Power’s Consolidated Balance Sheet.
(2) Current derivative liabilities are presented in other current liabilities in Virginia Power’s Consolidated Balance Sheet.
(3) Noncurrent derivative liabilities are presented in other deferred credits and other liabilities in Virginia Power’s Consolidated Balance Sheet.
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 Sheet and Statement of Income at December 31, 2009:
(1) Amounts deferred into AOCI have no associated effect in Virginia Power’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 Virginia Power’s Consolidated Statements of Income.
(3) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in interest and related charges.
(4) Amounts recorded in Virginia Power’s Consolidated Statements of Income are classified in electric fuel and other energy-related purchases.
(1) Includes derivative activity amortized out of regulatory assets/liabilities. Amounts deferred into regulatory assets/liabilities have no associated effect in Virginia Power’s Consolidated Statements of Income.
(2) Amounts are recorded in electric fuel and other energy-related purchases in Virginia Power’s Consolidated Statements of Income.
NOTE 9. EARNINGS PER SHARE
The following table presents the calculation of Dominion’s basic and diluted EPS:
(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, 2008 or 2007.
NOTE 10. INVESTMENTS
DOMINION
Equity and Debt Securities
RABBI TRUST SECURITIES
Marketable equity and debt securities and cash equivalents held in Dominion’s rabbi trusts and classified as trading totaled $96 million and $95 million at December 31, 2009 and 2008, respectively. Cost-method investments held in Dominion’s rabbi trusts totaled $17 million and $21 million at December 31, 2009 and 2008, respectively.
DECOMMISSIONING TRUST SECURITIES
Dominion holds marketable equity and debt securities and cash equivalents (classified as available-for-sale) 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.
(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes net assets related to the pending sales and purchases of securities of $11 million and $8 million at December 31, 2009 and 2008, respectively.
(3) The fair value of securities in an unrealized loss position was $169 million at December 31, 2009.
The fair value of Dominion’s marketable debt securities at December 31, 2009 by contractual maturity is as follows:
Combined Notes to Consolidated Financial Statements, Continued
Presented below is selected information regarding Dominion’s marketable equity and debt securities.
(1) The increase in proceeds in 2009 primarily reflects changes in asset allocation and liquidation of positions in connection with changes in fund managers.
(2) 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 as follows:
(1) Amounts include other-than-temporary impairment losses for debt securities of $13 million, $28 million and $7 million at December 31, 2009, 2008 and 2007, respectively.
Equity Method Investments
Investments that Dominion accounts for under the equity method of accounting are as follows:
(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, $52 million, and $35 million in 2009, 2008 and 2007, respectively. Excluding the 2009 distribution from Fowler Ridge, Dominion received distributions from these investments of $63 million, $12 million and $16 million in 2009, 2008, and 2007, respectively. As of December 31, 2009 and 2008, the carrying amount of Dominion’s investments exceeded Dominion’s share
of underlying equity in net assets by approximately $19 million and $45 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. During 2007, Dominion recognized an impairment loss of $11 million in connection with the expected sale of one of its equity method investments.
VIRGINIA POWER
Virginia Power holds marketable equity and debt securities and cash equivalents (classified as available-for-sale) 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.
(1) Included in AOCI and the decommissioning trust regulatory liability as discussed in Note 2.
(2) Includes net assets related to the pending sales and purchases of securities of $6 million at December 31, 2009 and 2008.
(3) The fair value of securities in an unrealized loss position was $88 million at December 31, 2009.
The fair value of Virginia Power’s debt securities at December 31, 2009, by contractual maturity is as follows:
Presented below is selected information regarding Virginia Power’s marketable equity and debt securities.
(1) The increase in proceeds in 2009 primarily reflects changes in asset allocation and liquidation of positions in connection with changes in fund managers.
(2) 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:
(1) Amounts include other-than-temporary impairment losses for debt securities of $7 million, $5 million and $1 million at December 31, 2009, 2008 and 2007, respectively.
NOTE 11. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment and their respective balances for the Companies are as follows:
Following the sale of Dominion’s non-Appalachian E&P operations, costs of unproved properties capitalized under the full cost method of accounting that were excluded from amortization at December 31, 2009 and 2008 were not material. There were no significant properties under development, as defined by the SEC, excluded from amortization at December 31, 2009 and 2008. As gas and oil reserves are proved through drilling or as properties are deemed to be impaired, excluded costs and any related reserves are transferred on an ongoing, well-by-well basis into the amortization calculation.
Amortization rates for capitalized costs under the full cost method of accounting for Dominion’s U.S. and Canadian cost centers were as follows:
(1) Reflects the amortization rate for capitalized costs for Dominion’s Canadian cost center as of June 2007. As a result of the sale of Dominion’s Canadian E&P operations in June 2007, it discontinued the amortization of capitalized unproved property costs for the Canadian cost center.
Combined Notes to Consolidated Financial Statements, Continued
Volumetric Production Payment Transactions
Dominion previously entered into VPP transactions in 2005, 2004 and 2003 for approximately 76 bcf for the period March 2005 through February 2009, 83 bcf for the period May 2004 through April 2008 and 66 bcf for the period August 2003 through July 2007, respectively. Cash proceeds received from these VPP transactions were recorded as deferred revenue. Dominion recognized revenue as natural gas was produced and delivered to the purchaser. The remaining deferred revenue amount was $248 million at December 31, 2006. During 2007, in conjunction with the sale of Dominion’s non-Appalachian E&P operations, Dominion paid $250 million to terminate the agreements and retained the VPP royalty interests formerly associated with these agreements. Production from VPP royalty interests declined significantly in 2009, reflecting the expiration of these interests in February 2009.
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. The net proceeds were credited to Dominion’s full cost pool, reducing property, plant and equipment in the Consolidated Balance Sheet, as the transaction did not significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil. Under the agreement, Dominion receives a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. Dominion retained the drilling rights in traditional formations both above and below the Marcellus Shale interval and continues its conventional drilling program on the acreage.
Sale of E&P Properties
In 2007, Dominion sold its non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion, which included the sale of a portion of its U.S. full cost pool and its entire Canadian full cost pool.
Jointly-Owned Power Stations
Dominion’s and Virginia Power’s proportionate share of jointly-owned power stations at December 31, 2009 is as follows:
(1) Station jointly owned by Virginia Power.
(2) Unit jointly owned by Dominion.
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 owner -
ship 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.
NOTE 12. GOODWILL AND INTANGIBLE ASSETS
Goodwill
The changes in Dominion’s carrying amount and segment allocation of goodwill are presented below:
(1) Goodwill amounts do not contain any accumulated impairment losses.
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 $155 million, $95 million and $115 million for 2009, 2008 and 2007, respectively. In 2009, Dominion acquired $196 million of intangible assets, primarily representing software and emissions allowances, with estimated weighted-average amortization periods of approximately 6 years and 1 year, respectively. Amortization expense for Virginia Power’s intangible assets was $26 million, $28 million, and $46 million for 2009, 2008 and 2007, respectively. In 2009, Virginia Power acquired $22 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:
Annual amortization expense for these intangible assets is estimated to be as follows:
NOTE 13. REGULATORY ASSETS AND LIABILITIES
Regulatory assets and liabilities include the following:
(1) Primarily reflects prior period unrecovered gas costs at Dominion’s regulated gas operations, which are recovered through quarterly filings with the Ohio Commission.
(2) Primarily reflects deferred fuel expenses for the Virginia jurisdiction of Virginia Power’s generation operations. See Note 14 for more information.
(3) Amounts to be recovered through a 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.
Combined Notes to Consolidated Financial Statements, Continued
(4) As discussed under Derivative Instruments in Note 2, for jurisdictions subject to cost-based 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, without interest.
(5) Reported in other current assets.
(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) Under the Ohio Percentage of Income Payment Plan (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 under the PIPP rider according to Dominion East Ohio tariff provisions. Although the current rider rate was designed to recover deferred costs over a three year period, unrecovered costs have increased. Accordingly, Dominion East Ohio filed for approval of an increase in the recovery rate on December 31, 2009. A ruling by the Ohio Commission is not expected before the end of the first quarter of 2010.
(8) 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.
(9) Reflects an annual true up to electric transmission rates and the deferral of transmission-related costs associated with Rider T. See Note 14 for more information.
(10) Costs recognized in excess of amounts included in regulated rates charged by Dominion’s regulated gas operations before rates were updated to reflect a new method of accounting and the cost related to the accrued benefit obligation recognized as part of accounting for Dominion’s acquisition of CNG.
(11) See Note 14 regarding the write-off of substantially all of these amounts since recovery is no longer probable based on the proposed settlement of Virginia Power’s rate case proceedings.
(12) Reflects a reserve associated with the proposed settlement of Virginia Power’s 2009 rate case proceedings. See Note 14 for more information.
(13) 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.
(14) 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.
At December 31, 2009, approximately $266 million of Dominion’s and $172 million of Virginia Power’s regulatory assets represented past expenditures on which they do not earn a return. The Companies’ expenditures consist primarily of Virginia sales taxes, deferred fuel costs and deferred transmission costs. In addition, Dominion’s expenditures 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
In March 2009, Virginia Power filed with the Virginia Commission, pursuant to the Regulation Act, a petition to recover from Virginia jurisdictional customers an annual net increase of approximately $78 million in costs related to FERC-approved transmission charges and PJM demand response programs. This amount also included a portion of the RTO start-up costs and administrative fees discussed further in Federal Regulation. In a final order in June 2009, the Virginia Commission approved recovery of approximately $218 million through Rider T, which
includes approximately $150 million of transmission-related costs that were traditionally incorporated in base rates, plus an incremental increase of approximately $68 million. The Virginia Commission also ruled that approximately $10 million that the Company had proposed to collect in Rider T would be more appropriately recovered through base rates, and those costs have been incorporated into the Company’s revised base rate filing that was submitted in July 2009. Rider T became effective on September 1, 2009 and increased a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $1.11 per month.
Virginia Power also has filed with the Virginia Commission an application for approval and cost recovery of eleven DSM programs, including one peak-shaving program and ten energy efficiency programs. Virginia Power plans to use DSM, along with its traditional and renewable supply-side resources, to meet its projected load growth over the next 15 years. The DSM programs provide the first steps toward achieving Virginia’s goal of reducing, by 2022, the electric energy consumption of the Company’s retail customers by ten percent of what was consumed in 2006. In February 2010, the Virginia Commission concluded an evidentiary hearing to consider the DSM programs and the related recovery. The Company has requested approval of two rate adjustment clauses for the associated cost recovery to be effective April 1, 2010. Specifically, the two rate adjustment clauses for recovery from Virginia jurisdictional customers represent an annual net increase in costs of approximately $48 million for the period April 1, 2010 to March 31, 2011. If approved by the Virginia Commission, the rate adjustment clauses will be expected, on a combined basis, to increase a typical 1,000 kWh residential bill by approximately $0.91 per month. The Regulation Act gives the Virginia Commission until the end of March 2010 to act on Virginia Power’s application.
In March 2009, Virginia Power filed with the Virginia Commission its first annual update to the rate adjustment clause for the Virginia City Hybrid Energy Center requesting an increase of approximately $99 million for financing costs to be recovered through rates in 2010. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to Rider S, plus the 100 basis point enhancement for construction of a new coal-fired generation facility, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009, at which Virginia Power presented a proposed Stipulation and Recommendation that, among other things, would reduce the increase in the revenue requirement by approximately $8 million to $91 million. In December 2009, the hearing examiner’s report was issued recommending approval of the Rider S increase as set forth in the proposed Stipulation, and thereafter the Virginia Commission approved the Rider S increase consistent with this recommendation. The Rider S revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding.
In March 2009, Virginia Power filed a petition with the Virginia Commission for the recovery of approximately $77 million of construction-related financing costs associated with Bear Garden through initiation of Rider R. As part of this filing Virginia Power requested that the 13.5% ROE proposed in its March 31, 2009 base rate filing be applied to the Bear Garden facility rate
adjustment clause, with a 100 basis point enhancement for construction of a combined-cycle facility, as authorized by the Regulation Act, for a requested total ROE of 14.5%. An evidentiary hearing was held before a hearing examiner in August 2009. In Virginia Power’s post-hearing brief, it unilaterally agreed to reduce the revenue requirement by $4 million to $73 million. In December 2009, the Virginia Commission approved Rider R with the $73 million revenue requirement for 2010. The Rider R revenue requirement approved for 2010 remains subject to revision to reflect the Virginia Commission’s ROE determination in the pending base rate proceeding. In accordance with the Virginia Commission’s approval of Rider R, the enhanced return will apply to the Bear Garden facility during construction and through the first ten years of the facility’s service life.
In March 2009, Virginia Power filed its Virginia fuel factor application with the Virginia Commission. The application requested an annual decrease in fuel expense recovery of approximately $236 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.893 cents per kWh to 3.529 cents per kWh, or approximately $3.64 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill. The proposed fuel factor went into effect on July 1, 2009 on an interim basis and an evidentiary hearing on the Company’s application was held on September 1, 2009. Consistent with a proposal made by the Company at the hearing in September 2009, the Virginia Commission issued an interim fuel order, effective October 1, 2009, further reducing the fuel factor by approximately $103 million for the period July 1, 2009 through June 30, 2010, a decrease from 3.529 cents per kWh to 3.310 cents per kWh, or approximately $2.19 per month for a typical 1,000 kWh Virginia jurisdictional residential customer’s bill. The cumulative decrease in the fuel factor for the period July 1, 2009 through June 30, 2010 reflects lower projected fuel expenses and a prospective credit against fuel expenses of certain FTRs allocated to the Company. In December 2009, the Virginia Commission issued another interim order decreasing Virginia Power’s fuel factor by approximately $119 million from 3.310 cents per kWh to 2.927 cents per kWh, a reduction of approximately $3.83 per month for the typical 1,000 kWh Virginia jurisdictional residential customer’s average bill, for service rendered on and after January 1, 2010. The Virginia Commission has not yet issued a final order.
Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned electric utilities in Virginia. In response, Virginia Power submitted base rate filings and accompanying schedules during 2009 to the Virginia Commission, which, as amended, propose to increase its Virginia jurisdictional base rates by approximately $250 million annually. Virginia Power’s initial March 2009 filing proposed a 12.5% ROE, plus an additional 100 basis point performance incentive pursuant to the Regulation Act based on Virginia Power’s generating plant performance, customer service, and operating efficiency, resulting in a total ROE request of 13.5%. In July 2009, in response to rulings by the Virginia Commission relating to the appropriate rate year and capital structure to be used in the Virginia Power’s base rate review, the Company submitted a revised filing reflecting a number of adjustments, including an upward adjustment of 50 basis points in the proposed ROE. The
base rate increase became effective on an interim basis on September 1, 2009, subject to refund and adjustment by the Virginia Commission and increased a typical 1,000 kWh Virginia jurisdictional residential customer’s bill by approximately $5.22 per month.
In November 2009, Virginia Power and the Office of the Attorney General of Virginia, Division of Consumer Counsel, and certain other interested parties, filed a Stipulation and Recommendation for consideration and requested approval by the Virginia Commission that would resolve the pending proceeding to set base rates in Virginia, the Virginia fuel case proceeding and the authorized ROE for the rate adjustment clauses for the Virginia City Hybrid Energy Center, Bear Garden and the DSM programs. The November 2009 Stipulation entails, among other things, a partial refund of 2008 earnings and other amounts, an authorized ROE applicable to base rates of 11.9%, an authorized ROE applicable to the Virginia City Hybrid Energy Center and Bear Garden rate adjustment clauses of 12.3% and continuation of Virginia Power’s base rates in existence prior to September 1, 2009. An evidentiary hearing in the base rate review has been completed, at which evidence relating to both Virginia Power’s request for a base rate increase and the November 2009 Stipulation was presented. Not all of the parties to the base rate review or the related proceedings supported the November 2009 Stipulation. In February 2010, Virginia Power filed a revised Stipulation and Recommendation with the Virginia Commission. As compared to the November 2009 Stipulation, the February 2010 Stipulation has the support of all parties, including the Staff of the Virginia Commission and reflects an increase in the amounts to be refunded to customers. Virginia Power’s 2009 results include a charge of $782 million ($477 million after-tax) representing its best estimate of the probable outcome of this matter. Of this amount, $700 million ($427 million after-tax) represents a partial refund of 2008 revenues and other amounts, and $82 million ($50 million after-tax) represents an expected refund of 2009 revenues collected from customers as a result of the implementation of a base rate increase that became effective on an interim basis on September 1, 2009. Of the total $782 million pre-tax charge, $523 million was recorded in operating revenue, $129 million was recorded in electric fuel and other energy-related purchases expense, and $130 million was recorded in other operations and maintenance expense in Virginia Power’s Consolidated Statement of Income. The charge resulted in a $259 million decrease in regulatory assets, reflecting the write off of $129 million of previously deferred fuel costs and $130 million of previously deferred RTO costs since recovery is no longer probable based on the proposed February 2010 Stipulation, as well as a $473 million increase in regulatory liabilities with the remainder recorded to other receivables and payables in Virginia Power’s Consolidated Balance Sheet. Dominion’s 2009 results include an additional charge of $12 million ($8 million after-tax) recorded in other operations and maintenance expense, reflecting the write-off of previously deferred RTO costs since recovery is no longer probable based on the proposed February 2010 Stipulation. Outcomes of the base rate review could include adoption of the terms of the February 2010 Stipulation, or alternatively, a rate increase, a rate decrease, or a partial refund of 2008 earnings deemed more than 50 basis points above the authorized ROE.
Combined Notes to Consolidated Financial Statements, Continued
If the Virginia Commission’s future rate actions, including actions relating to Virginia Power’s 2009 base rate review, DSM programs, recovery of Virginia fuel expenses, and additional rate adjustment clause filings differ materially from Virginia Power’s expectations it could adversely affect its results of operations, financial condition and cash flows.
In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route proposed for the line which is adjacent to, or within, existing transmission line right-of-ways. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In March 2009, the Sierra Club filed an appeal and request for stay of the West Virginia Commission’s approval, which was subsequently denied by the Supreme Court of West Virginia in April 2009. An appeal of the Pennsylvania Commission’s approval by the Energy Conservation Council of Pennsylvania is pending. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. In November 2009, the Virginia Supreme Court affirmed the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and, subject to the receipt of all regulatory approvals, is expected to be completed in June 2011.
North Carolina Regulation
In 2004, the North Carolina Commission commenced a review of Virginia Power’s North Carolina base rates and subsequently ordered Virginia Power to file a general rate case to show cause why its North Carolina jurisdictional base rates should not be reduced. The rate case was filed in September 2004, and in March 2005 the North Carolina Commission approved a settlement that included a prospective $12 million annual reduction in base rates and a five-year base rate moratorium, effective as of April 2005. Fuel rates are still subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.
In February 2010, Virginia Power filed an application with the North Carolina Commission to increase its electric retail rates in North Carolina by approximately $46 million effective January 2011. The requested rate increase would consist of a base rate increase of approximately $29 million and approximately $17 million in purchased power costs to be recovered by means of the existing pass-through fuel adjustment charge. These purchased power costs have previously been considered part of the Company’s cost of service for recovery through base rates. The application entails a proposed ROE of 11.9%. The proposed base rate increase of $29 million would increase a typical 1,000 kWh North Carolina jurisdictional customer’s bill by approximately 9% or $8.96 per month when compared to residential bills under the currently approved rates. If the entire $17 million increase related to purchased power costs were to be approved for recovery in the 2011 fuel adjustment charge, and if none of those costs are
offset by reductions in costs for other fuel types, the additional impact on residential customer bills would be approximately 5% or $4.94 per month. It is anticipated that a public hearing on the proposed base rate increase will be consolidated with the Company’s annual fuel adjustment proceeding in the fourth quarter of 2010 so as to facilitate a North Carolina Commission order in both matters before the end of 2010.
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 that issue back to FERC for further proceedings. Dominion and Virginia Power cannot predict the outcome of the FERC proceedings on remand.
In July 2008, Virginia Power filed an application with FERC requesting a revision to its cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects. Under the proposal, the cost of transmission service would increase to include an ROE incentive adder for each of the eleven projects, beginning the date each project enters commercial operation (but not before January 1, 2009). Virginia Power proposed an incentive of 150 basis points or 1.5% for four of the projects (including the Meadow Brook-to-Loudoun line and Carson-to-Suffolk line) and an incentive of 125 basis points or 1.25% for the other seven projects. In August 2008, FERC approved the proposal, effective September 1, 2008. The total cost for all eleven projects is estimated at $877 million, and all projects are currently expected to be completed by 2012. Numerous parties sought rehearing of the FERC order in August 2008 and rehearing is pending. Virginia Power cannot predict the outcome of the rehearing.
In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Commission, New Jersey Board of Public Utilities and several other organizations representing consumers in the PJM region (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing was denied in June 2009. A notice of appeal was filed in August 2009 by the
Maryland Public Service Commission and the New Jersey Board of Public Utilities at the U.S. Court of Appeals for the Fourth Circuit. Dominion and Virginia Power cannot predict the outcome of the appeal.
In December 2008, FERC approved the Companies’ DRC request to become effective January 1, 2009, which would allow recovery of approximately $153 million of Dominion’s RTO costs, including $140 million at Virginia Power, that were deferred due to a statutory base rate cap established under Virginia law. In June 2009, the Virginia Commission approved full recovery of the DRC from Virginia Power’s retail customers through Rider T. Recovery of the DRC began September 1, 2009. In July 2009, FERC issued an order denying the Office of the Attorney General of Virginia and the Virginia Commission’s requests for rehearing of its December 2008 order. Notices of appeal were filed in September 2009 at the U.S. Court of Appeals for the Fourth Circuit and the appeal is currently pending. In the fourth quarter of 2009, Dominion recorded a charge of $142 million ($87 million after tax), including $130 million ($79 million after tax) at Virginia Power to write off substantially all of these regulatory assets, since recovery is no longer probable based on the proposed settlement of Virginia Power’s rate case proceedings discussed in Electric Regulation in Virginia.
Dominion Transmission Rates
In December 2007, DTI and the Independent Oil and Gas Association of West Virginia, Inc. reached a settlement agreement on DTI’s gathering and processing rates for the period January 1, 2009 through December 31, 2011. This settlement maintained the gas retainage fee structure that DTI has had since 2001. The rates are 10.5% for gathering and 0.5% for processing. Under the settlement, DTI continues to retain all revenues from its liquids sales, thus maintaining cash flow from the liquids business. In connection with the settlement, DTI has committed to invest at least $20 million annually in Appalachian gathering-related assets. The new rates have been approved by FERC as negotiated rates.
NOTE 15. ASSET RETIREMENT OBLIGATIONS
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 and interim retirements of natural gas gathering, transmission, distribution and storage pipeline components. These obligations result from certain safety and environmental activities Dominion is required to perform when any pipeline is abandoned or asbestos is disturbed.
There are also AROs related to retirement of Dominion’s LNG facility, gas storage wells in its underground natural gas storage network, certain Virginia Power electric transmission and distribution assets located on property with easements, right of ways, franchises and leases agreements, and Virginia Power’s hydroelectric generation facilities. In addition, Dominion’s and Virginia Power’s AROs include the future abatement of asbestos in their 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 were as follows:
(1) Includes $20 million and $9 million reported in other current liabilities at December 31, 2008 and 2009, 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 and $1 million reported in other current liabilities at December 31, 2008 and 2009, respectively.
Dominion and Virginia Power have established trusts dedicated to funding the future decommissioning of their nuclear plants. At December 31, 2009 and 2008, the aggregate fair value of Dominion’s trusts, consisting primarily of equity and debt securities, totaled $2.6 billion and $2.2 billion, respectively. At December 31, 2009 and 2008, the aggregate fair value of Virginia Power’s trusts, consisting primarily of debt and equity securities, totaled $1.2 billion and $1.1 billion, respectively.
NOTE 16. VARIABLE INTEREST ENTITIES
An entity is considered a VIE if it does not have sufficient equity to finance its activities without assistance from variable interest holders or if its equity investors lack any of the following characteristics of a controlling financial interest:

control through voting rights,

the obligation to absorb expected losses, or

the right to receive expected residual returns.
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 receives the majority of a VIE’s expected losses, expected residual returns, or both.
Virginia Power has long-term power and capacity contracts with four non-utility generators with an aggregate generation
Combined Notes to Consolidated Financial Statements, Continued
capacity of approximately 940 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 was based primarily on a qualitative assessment of its variable interests as compared to the operations, commodity price and other risks retained by the equity and debt holders 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 $1.7 billion as of December 31, 2009. Virginia Power paid $210 million, $205 million, and $211 million for electric capacity and $117 million, $196 million, and $160 million for electric energy to these entities for the years ended December 31, 2009, 2008 and 2007, 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 $416 million, $397 million, and $344 million for the years ended December 31, 2009, 2008 and 2007, 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 and Virginia Power use short-term debt to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. 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 under its commodities hedging program. Collateral requirements are impacted by commodity prices, hedging levels, Dominion’s credit quality and the credit quality of its counterparties.
Virginia Power’s short-term financing is supported by a five-year joint revolving credit facility with Dominion. This credit facility is being used for working capital, as support for the combined commercial paper programs of Dominion and Virginia Power and for other general corporate purposes.
Commercial paper, bank loans, and letters of credit outstanding, as well as capacity available under credit facilities were as follows:
(1) 2008 amounts exclude commitments provided by Lehman.
(2) This credit facility was entered into February 2006 and terminates in February 2011. 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 of letters of credit. At December 31, 2009, total outstanding commercial paper was $442 million, all of which were Virginia Power’s borrowings, with a weighted-average interest rate of 0.28%. At December 31, 2008, total outstanding commercial paper was $297 million, all of which were Virginia Power’s borrowings, with a weighted-average interest rate of 5.92%. At December 31, 2009, total outstanding letters of credit were $153 million, of which $104 million were issued on Virginia Power’s behalf. At December 31, 2008, total outstanding letters of credit were $187 million, of which less than $86 million were issued on Virginia Power’s behalf.
(3) This credit facility was entered into August 2005 and terminates in August 2010. This facility can be used to support bank borrowings, the issuance of letters of credit and commercial paper. The weighted-average interest rates of the outstanding bank borrowings supported by this facility were 0.33% and 3.95% at December 31, 2009 and 2008, respectively.
(4) This facility was entered into December 2005 and terminates in December 2010. This credit facility can be used to support commercial paper and letter of credit issuances.
(5) The weighted-average interest rates of the outstanding commercial paper supported by Dominion’s credit facilities were 0.30% and 5.87% at December 31, 2009 and 2008, respectively.
(6) This credit facility was entered into in July 2008 and terminated in July 2009.
In addition to the credit facility commitments disclosed above, Virginia Power also has a five-year $120 million credit facility that terminates in February 2011, which supports certain of its tax-exempt financings.
Dominion and Virginia Power plan to replace their existing credit facilities during the second or third quarter of 2010. They expect to operate with credit facilities ranging from $3.0 to $3.5 billion. The Companies do not expect the reduction in the size of their credit facilities to negatively impact their ability to fund their operations.
Combined Notes to Consolidated Financial Statements, Continued
NOTE 18. LONG-TERM DEBT
(1) Represents weighted-average coupon rates for debt outstanding as of December 31, 2009.
(2) These financings relate to certain pollution control equipment at Virginia Power’s generating facilities. The variable rate tax-exempt financings are supported by a $120 million five-year credit facility that terminates in February 2011.
(3) $60 million of tax-exempt bonds due in 2040 issued by the Industrial Development Authority of Wise County on behalf of Virginia Power in September 2009 are not included upon consolidation because the bonds have been temporarily purchased and are held by Virginia Power.
(4) Represents the valuation of certain fair value hedges associated with Virginia Power’s and Dominion’s fixed-rate debt.
(5) Includes $(1) million of unamortized discount and $1 million of fair value hedge valuation in 2009 and 2008, respectively.
(6) At the option of holders, $510 million of Dominion’s 5.25% senior notes due 2033 and $600 million of Dominion’s 8.875% senior notes due 2019 are subject to redemption at 100% of the principal amount plus accrued interest in August 2015 and January 2014, respectively.
(7) Convertible into a combination of cash and shares of Dominion’s common stock at any time when the closing price of 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. At the option of holders on December 15, 2011, 2013 or 2018, these securities are subject to redemption at 100% of the principal amount plus accrued interest. These securities are currently non-callable by Dominion until December 15, 2011.
(8) Represents debt assumed by Dominion from the merger of its former CNG subsidiary.
(9) Represents debt associated with Dominion’s Kincaid power station. The debt is non-recourse to Dominion and is secured by the facility’s assets ($623 million at December 31, 2009) and revenue.
(10) Includes $2 million of net unamortized discount and fair value hedge valuation and $9 million of fair value hedge valuation in 2009 and 2008, respectively.
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, 2009, 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, 2009, there were no events of default under these covenants.
Convertible Securities
As of December 31, 2009, Dominion has $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, 2009, the conversion rate had been adjusted to 28.1237 shares, primarily due to individual dividend payments above the level paid at issuance. In January 2010, Dominion’s Board of Directors declared dividends payable March 20, 2010 of 45.75 cents per share of common stock which will increase the conversion rate to 28.22 effective as of February 24, 2010.
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 of $36.80 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 exceeds the applicable conversion price ($42.52 as of February 24, 2010) 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.
The senior notes have not been eligible for conversion during 2009 and as of December 31, 2009, the closing price of Dominion’s common stock was not equal to $42.67 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 2010. During 2008, approximately $18 million of the contingent convertible senior notes were converted by holders. 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. In December 2008, Dominion amended the terms of its Series C 2.125% Convertible Senior Notes and the related Twenty-Seventh Supplemental Indenture. The amendment eliminates Dominion’s ability to redeem the Notes before December 2011. The amendment also establishes a new repurchase date in December 2011. 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 holds 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.
Combined Notes to Consolidated Financial Statements, Continued
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.
In July and August 2007, Dominion repaid $248 million of its 8.4% unsecured junior subordinated notes and redeemed approximately 240 thousand units of the $250 million 8.4% Dominion Resources Capital Trust III preferred securities due January 15, 2031. The securities were redeemed at an average price of $1,209 per preferred security plus accrued and unpaid distributions.
In July 2007, Dominion repaid $206 million of its 7.8% unsecured junior subordinated notes and redeemed all 8 million units of the $200 million 7.8% Dominion CNG Capital Trust I preferred securities due October 31, 2041. The 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, 2009:
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:
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 the 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 2006 Series A Enhanced Junior Subordinated Notes due 2066 (June 2006 hybrids) and $500 million of 2006 Series B Enhanced Junior Subordinated Notes due 2066 (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 its 8.375% Series A Enhanced Junior Subordinated Notes (June 2009 hybrids) that will mature in 2064, subject to extensions no later than 2079. The June 2009 hybrids are listed on the New York Stock Exchange under the symbol DRU.
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, 2009 or 2008.
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, 2009 and 2008. Upon involuntary liquidation, dissolution or winding-up of Virginia Power, each share would be entitled to receive $100 plus accrued dividends. Dividends are cumulative.
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, or 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 not subject to mandatory redemption that were outstanding as of December 31, 2009:
(1) Through 7/31/2010; $101.06 commencing 8/1/2010; amounts decline in steps thereafter to $100.00 by 8/1/2013.
(2) Through 8/31/2010; $101.05 commencing 9/1/2010; amounts decline in steps thereafter to $100.00 by 9/1/2013.
(3) Dividend rate was 5.50% through 12/20/2007. Dividend rate is now 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
In January 2009, Dominion entered into sales agency agreements pursuant to which Dominion may offer from time to time up to $400 million aggregate amount of its common stock. Sales of common stock can be made by means of privately negotiated transactions, as transactions on the New York Stock Exchange at market prices or in such other transactions as are agreed upon by Dominion and the sales agents and in conformance with applicable securities laws.
During 2009, Dominion issued 14 million shares of common stock for cash proceeds of $456 million. Dominion issued 6.2 million shares through at-the-market issuances under its sales agency agreements and received cash proceeds of $191 million, net of fees and commissions paid of $2 million. Following these issuances, Dominion has the ability to issue up to $207 million of stock under sales agency agreements. Dominion also issued 76,000 shares of its common stock to its officers and directors under a private placement program for aggregate consideration of approximately $2 million. The remainder of the shares issued and cash proceeds received during 2009 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.
Additionally, in February 2009, Dominion issued approximately 1.6 million shares of common stock to an existing holder of its senior notes, in a privately negotiated transaction, in exchange for approximately $56 million of the principal of two series of its outstanding senior notes, which were retired. The transaction was exempt from registration pursuant to Section 3(a)(9) of the Securities Act and no commission or remuneration was paid in connection with the exchange.
VIRGINIA POWER
In 2009, Virginia Power issued 31,877 shares of its common stock to Dominion reflecting the conversion of $1 billion of short-term demand note borrowings from Dominion to equity.
Shares Reserved for Issuance
At December 31, 2009, Dominion had approximately 62 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.
Accumulated Other Comprehensive Income (Loss)
Presented in the table below is a summary of AOCI by component:
Stock-Based Awards
In April 2005, Dominion’s shareholders approved the 2005 Incentive Compensation Plan (2005 Incentive Plan) for employees and the Non-Employee Directors Compensation Plan (Non-Employee Directors Plan). In May 2009, Dominion’s shareholders approved an amendment and restatement of the 2005 Incentive Plan. The 2005 Incentive Plan, as amended, 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, 2009, approximately 34 million shares were available for future grants under these plans. Prior to April 2005, Dominion had an incentive compensation plan that provided stock options and restricted stock awards to directors, executives and other key employees with vesting periods from one to five years. Stock options generally had contractual terms from six and one half to ten years in length.
Combined Notes to Consolidated Financial Statements, Continued
Dominion measures and recognizes compensation expense relating to share-based payment transactions based on the fair value of the equity or liability instruments issued. Dominion’s results for the years ended December 31, 2009, 2008 and 2007 include $44 million, $46 million, and $57 million, respectively, of compensation costs and $17 million, $17 million, and $21 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, 2009, 2008 and 2007, Dominion realized $5 million, $7 million, and $46 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, 2009, 2008 and 2007. No options were granted under any plan in 2009, 2008 or 2007.
(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 $49 million, $43 million, and $226 million in the years ended December 31, 2009, 2008 and 2007, 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. Restricted stock awards generally vest over a three-year service period. The following table provides a summary of restricted stock activity for the years ended December 31, 2009, 2008 and 2007:
As of December 31, 2009, unrecognized compensation cost related to nonvested restricted stock awards totaled $21 million and is expected to be recognized over a weighted-average period of 1.4 years. The fair value of restricted stock awards that vested was $29 million, $40 million, and $30 million in 2009, 2008 and 2007, 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. Shares tendered for taxes are added to the shares remaining to be issued and become available for reissuance as incentive awards.
GOAL-BASED STOCK
In recent years, goal-based stock awards have been granted to key contributors who are non-officer employees. Goal-based stock awards have also been granted in lieu of cash-based performance grants to certain officers who have not achieved a certain targeted level of share ownership. Current outstanding goal-based shares include awards granted in April 2008, February 2009 and April 2009.
The issuance of awards is based on the achievement of multiple performance metrics during a two-year period, including return on invested capital, book value per share, and total shareholder return 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 2006 grants ended on December 31, 2007, the CGN Committee determined the actual performance against metrics established for those awards, and 130 thousand shares of the outstanding goal-based stock awards granted in April 2006 were converted to 200 thousand shares of restricted stock for the remaining term of the vesting period ending in April 2009.
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.
The following table provides a summary of goal-based stock activity for the years ended December 31, 2009, 2008 and 2007:
At December 31, 2009, the targeted number of shares expected to be issued under the April 2008, February 2009 and April 2009 awards was approximately 323 thousand. In January 2010, the CGN Committee determined the actual performance against metrics established for the April 2008 awards with a performance period that ended December 31, 2009. Based on that
determination, the total number of shares to be issued under the goal-based stock awards was approximately 365 thousand.
As of December 31, 2009, unrecognized compensation cost related to nonvested goal-based stock awards totaled $7 million and is expected to be recognized over a weighted-average period of 1.5 years.
CASH-BASED PERFORMANCE GRANT
Cash-based performance grants are made to Dominion’s officers under Dominion’s Long-Term Incentive Program. 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 2006 was $13 million, but the actual payout of the award in February 2008 determined by the CGN Committee was $18 million, based on the level of performance metrics achieved. At December 31, 2007, a liability of $18 million had been accrued for this award.
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. At December 31, 2008, a liability of $16 million had been accrued for this award.
In April 2008, a cash-based performance grant was made to officers. Payout of the performance grant occurred in February 2010 based on the achievement of three performance metrics during 2008 and 2009: return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies. At December 31, 2009, the targeted amount of the grant was $12 million. Based on the achievement of the performance metrics, payout of the 2008 cash-based performance grants was $15 million. 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. Payout of the performance grant will occur by March 15, 2011 based on the achievement of three performance metrics during 2009 and 2010: return on invested capital, book value per share and total shareholder return relative to that of a peer group of companies. At December 31, 2009, the targeted amount of the grant was $11 million and a liability of $5 million had been accrued for this award.
NOTE 21. 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, 2009, 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’s or Virginia Power’s ability to pay dividends or receive dividends from their subsidiaries at December 31, 2009.
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.
Combined Notes to Consolidated Financial Statements, Continued
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.
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 $777 million in 2009 and negative $1.4 billion in 2008, versus expected returns of $462 million and $484 million, respectively. Differences between actual and expected returns on plan assets are accumulated and amortized during future periods. As such, investment-related declines in these trusts, such as those experienced during 2008, 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.
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was signed into law. The Medicare Act introduces a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree healthcare benefit plans that provide a 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 2009 and 2008, Dominion received a federal subsidy of $4 million and $3 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:
(1) Represents split-dollar life insurance liability resulting from the adoption of new accounting guidance for deferred compensation and postretirement benefit aspects of endorsement split-dollar life insurance
arrangements on January 1, 2008. This accounting guidance requires an employer to recognize a liability for future obligations (employee benefits) related to its endorsement split-dollar life insurance plans where benefits extend into postretirement periods.
(2) Represents pension plan assets classified as assets held for sale for Peoples at December 31, 2009 and Peoples and Hope at December 31, 2008, and other postretirement benefit plan obligations classified as liabilities held for sale for Peoples at December 31, 2009 and Peoples and Hope at December 31, 2008, in Dominion’s Consolidated Balance Sheets.
The accumulated benefit obligation (ABO) for all of Dominion’s defined benefit pension plans was $3.6 billion and $3.4 billion at December 31, 2009 and 2008, 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. No contributions to its pension plans are currently expected in 2010. 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 $56 million to the Dominion VEBAs in 2010.
Dominion does not expect any pension or other postretirement plan assets to be returned to the Company during 2010.
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:
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:
The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid:
The above benefit payments for other postretirement benefit plans are expected to be offset by Medicare Part D subsidies of approximately $5 million in 2010, $6 million annually for the period 2011 through 2013, $7 million in 2014 and $44 million during the period 2015 through 2019.
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 34% U.S. equity, 12% non-U.S. equity, 22% fixed income, 7% real estate and 25% other, such as private equity 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 securities 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 and commingled funds. Real estate includes equity real estate investment trusts (REITs) and investments in commingled funds and partnerships. Other investments include partnership investments in private equity and other funds that follow several different strategies.
Dominion maximizes the use of observable inputs and minimizes 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, Dominion seeks price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, or if Dominion believes that observable pricing is not indicative of fair value, judgment is required to develop the estimates of fair value.
The Plan’s investments are valued based on the values of the investments and the underlying investments which have been determined as follows:

Securities, Mutual Funds and REITs-Investments in U.S. government securities, corporate debt instruments, common and preferred stock, registered investment companies and mutual funds are presented at fair value using quoted market prices in active markets, including quoted prices for similar assets or liabilities in active markets, and quoted prices for identical or similar assets or liabilities in inactive markets.

Commingled Funds-Investments in commingled funds are stated at fair value, which has been determined based on the unit value of each fund. Unit values are determined by dividing the net asset value of the fund (based on the fair value of the underlying investments) by the total number of units outstanding.

Partnerships-Investments in partnerships are generally valued using net asset value based on Dominion’s proportionate share of the partnership’s 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 Dominion’s measurement date.
Combined Notes to Consolidated Financial Statements, Continued
Dominion also utilizes 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 it has the ability to access at the measurement date.

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.

Level 3-Unobservable inputs for the asset or liability, including situations where there is little, if any, market activity for the asset or liability.
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. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable 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.
The fair values of Dominion’s pension plan assets by asset category are as follows:
(1) Excludes net assets related to cash and pending sales and purchases of securities of $14 million and $17 million at December 31, 2009 and 2008, respectively.
The fair values of Dominion’s other postretirement plan assets by asset category are as follows:
(1) Excludes net assets related to cash and pending sales and purchases of securities of $1 million each at December 31, 2009 and 2008.
The following table presents the changes in Dominion’s pension plan and other postretirement plan assets that are measured at fair value and included in the Level 3 fair value category:
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.
Combined Notes to Consolidated Financial Statements, Continued
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:
(1) Relates to the sale of Dominion’s non-Appalachian E&P operations and the impact of distributions to retired executives.
(2) Represents a one-time benefit enhancement for certain employees in connection with the disposition of Dominion’s non-Appalachian E&P business.
The components of AOCI and regulatory assets and liabilities that have not been recognized as components of periodic benefit (credit) cost are as follows:
(1) 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. As of December 31, 2008, of the $2 billion and $431 million related to pension benefits and other postretirement benefits, $1.1 billion and $228 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, 2009 that are expected to be amortized as components of periodic benefit cost in 2010:
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
•
The types of investments expected to be held by the plans.
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:
In addition, Dominion sponsors defined contribution thrift-type savings plans. During 2009, 2008 and 2007, Dominion recognized $42 million, $39 million and $37 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. Virginia Power’s net periodic pension cost related to this plan was $48 million, $32 million and $37 million in 2009, 2008 and 2007, respectively. Employee compensation is the basis for determining Virginia Power’s share of total pension costs. Virginia Power did not contribute to the pension plan in 2009, 2008 or 2007.
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 $55 million, $33 million and $24 million in 2009, 2008 and 2007, respectively. Employee headcount is the basis for determining Virginia Power’s share of total 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 $34 million, $15 million and $7 million in 2009, 2008 and 2007, respectively. Virginia Power expects to contribute $35 million to the VEBA in 2010.
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. Investment-related declines in these trusts, such as those experienced during 2008, 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 employee savings plans that cover substantially all employees. Employer matching contributions of $14 million, $14 million and $12 million were incurred in 2009, 2008 and 2007, respectively.
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, 2009, 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:
(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, 2009, the present value of Virginia Power’s total commitment for capacity payments is $2 billion. Capacity payments totaled $356 million, $379 million, and $410 million, and energy payments totaled $254 million, $372 million, and $360 million for 2009, 2008 and 2007, respectively.
Combined Notes to Consolidated Financial Statements, Continued
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, 2009 are as follows:
Rental expense for Dominion totaled $172 million, $160 million, and $185 million for 2009, 2008 and 2007, respectively. Rental expense for Virginia Power totaled $49 million, $39 million, and $37 million for 2009, 2008, and 2007, respectively. The majority of rental expense is reflected in other operations and maintenance expense.
Dominion leases the Fairless power station, 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; 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
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.
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 March 2005, the EPA Administrator signed both CAIR and CAMR.
In February 2008, Dominion received a request for information pursuant to Section 114 of the CAA from the EPA. The request concerns historical operating changes and capital improvements undertaken at Dominion’s State Line and Kincaid power stations. In April 2009, Dominion received a second request for information. Dominion provided information in response to both requests. Also in April, Dominion received a Notice and Finding of Violations from the EPA claiming new source review violations, new source performance standards violations, and Title V permit program violations pursuant to the CAA and the respective State Implementation Plans. Dominion is currently evaluating the impact of the Notice and cannot predict the outcome of this matter.
In February 2008, the D.C. Appeals Court issued a ruling that vacates CAMR as promulgated by the EPA. The EPA Administration has announced that the EPA will proceed with a Maximum Achievable Control Technology rulemaking for coal and oil-fired electric utility steam generating units. These rules could require significant reductions in mercury and other hazardous air pollutants 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 D.C. Appeals Court issued a ruling vacating CAIR as promulgated by the EPA. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA, so the CAIR rules remain in effect. The remand allows CAIR to remain in place until such time that the EPA develops and implements a new rulemaking addressing the issues identified by the Court. Dominion and Virginia Power cannot predict how a new rulemaking will impact future SO2 and NOX emission reduction requirements beyond CAIR. In January 2010, the EPA proposed a new, more stringent National Ambient Air Quality Standard for ozone, which could require additional NOX controls in certain areas where the Companies operate.
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 the Clean Air Visibility Rule if those rules proceed, 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 the federal CAA and state regulatory requirements, Dominion and Virginia Power estimate that they will make capital expenditures at their affected generating facilities of approximately $597 million and $159 million, respectively, during the period 2010 through 2014.
In December 2009, the EPA issued their Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act, finding that GHGs “endanger both the public health and the public welfare of current and future generations.” If GHGs become regulated pollutants under the CAA, Dominion and Virginia Power will be required to obtain permits for GHG emissions from new and modified
facilities and amend operating permits for major sources of GHG emissions. Until these actions occur, and the EPA establishes guidance for GHG permitting, including Best Available Control Technology, it is not possible to determine the impact on Dominion’s or Virginia Power’s facilities that emit GHGs.
WATER
The Clean Water Act 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 Clean Water Act programs at their operating facilities. In July 2004, the EPA published regulations under Clean Water Act 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 Clean Water Act 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. Dominion and Virginia Power cannot predict the outcome of the judicial or EPA regulatory processes, nor can they determine with any certainty what specific controls may be required.
In August 2006, the Connecticut Department of Environmental Protection issued a notice of a Tentative Determination to renew the National Pollutant Discharge Elimination System permit for Dominion’s Millstone power station, which included a draft copy of the revised permit. In October 2007, Connecticut Department of Environmental Protection 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 Connecticut Department of Environmental Protection 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 Connecticut Department of Environmental Protection Commissioner issue the revised draft permit without change. A final determination is expected to be issued by the Connecticut Department of Environmental Protection in 2010. Until the final permit is reissued, it is not possible to predict any financial impact that may result.
In October 2003, the EPA and the Massachusetts Department of Environmental Protection each issued new National Pollutant Discharge Elimination System permits for Dominion’s Brayton Point power station. 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 $650 million, which is included in its planned capital expenditures through 2014.
In October 2007, the Virginia State Water Control Board issued a renewed water discharge (VPDES) permit for Virginia Power’s North Anna power station. The Blue Ridge Environmental Defense League, and other persons, appealed the Virginia State Water Control Board’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 Virginia State Water Control Board 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. Until the appeals process is complete and any revised permit is issued, it is not possible to predict any financial impact that may result.
SOLID AND HAZARDOUS WASTE
The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, provides for an 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 Comprehensive Environmental Response, Compensation and Liability Act of 1980, 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 potentially responsible parties 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
Combined Notes to Consolidated Financial Statements, Continued
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.
The EPA has announced that it will propose regulations for management of coal combustion byproducts at power plants under the Resource Conservation and Recovery Act. It is expected that such regulations will address ash impoundments, ash landfills, and ash handling practices. If these regulations are adopted, significant expenditures could be required at facilities that generate coal combustion byproducts. Due to the uncertain nature of the content and timing of these regulations, Dominion and Virginia Power cannot predict the financial impact at this time.
CLIMATE CHANGE LEGISLATION AND REGULATION
In June 2009, the U.S. House of Representatives passed comprehensive legislation titled the “American Clean Energy and Security Act of 2009” to encourage the development of clean energy sources and reduce GHG emissions. The legislation contains provisions establishing federal renewable energy standards for electric suppliers. The legislation also includes cap-and-trade provisions for the reduction of GHG emissions. Similar legislation has been introduced in the U.S. Senate. In addition, the EPA has proposed one rule and finalized another rule that together hold that GHGs are air pollutants subject to the provisions of the CAA. These are the EPA Final Endangerment and Cause or Contribute Findings for Greenhouse Gases Under Section 202(a) of the Clean Air Act and the Proposed Rulemaking To Establish Light-Duty Vehicle Greenhouse Gas Emission Standards and Corporate Average Fuel Economy Standards (proposed September 2009). Possible outcomes from these actions include regulation of GHG emissions from various sources, including electric generation and gas transmission and distribution facilities.
Dominion and Virginia Power currently support the enactment of federal legislation that regulates GHG emissions economy-wide, establishes a system of tradable allowances, slows the growth of GHG emissions in the near term and reduces GHG emissions in the long term. In addition, the Companies support legislation that sets a realistic baseline year and schedule and that is designed in a way to limit potential harm to the economy and competitive businesses.
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 on Climate Change formulated its recommendations to the Governor.
In July 2008, Massachusetts passed the Global Warming Solutions Act. Among other provisions, the Global Warming Solutions Act 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 Global Warming Solutions Act have not yet been proposed. Dominion operates two coal/oil-fired generating power stations in Massachusetts that are subject to the implementation of the Global Warming Solutions Act.
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.
Until December 31, 2008, two of Dominion’s facilities in Massachusetts, Brayton Point and Salem Harbor, were subject to existing regulations on CO2 under Massachusetts Regulation 310 CMR 7.29. These facilities could comply with these regulations either through procurement of GHG emission credits or payment into the Massachusetts GHG Expendable Trust. The combined 2008 CO2 compliance obligation for these two power stations was 474,687 tons of CO2, which was settled by September 1, 2009. Dominion procured 381,864 tons of GHG emissions credits from a combination of Dominion’s GHG emission credit projects (251,582 tons), as well as procurement from third party projects (130,282 tons). Payment into the GHG Expendable Trust for the two power stations covered the remainder of Dominion’s compliance obligation. This Massachusetts CO2 program is now superseded by RGGI. 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 and for developing nations to commit to “national appropriate mitigation actions”. The U.S. is expected to participate in this process.
The cost of compliance with future GHG emission reduction programs could be significant. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, Dominion and Virginia Power cannot predict the financial impact of future GHG emission reduction programs on their operations or their customers at this time.
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 2009 calculation for the NRC minimum financial assurance amount, aggregated for Dominion’s and Virginia Power’s nuclear units, was $2.6 billion and $1.5 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. 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 $12.5 billion of liability protection per nuclear incident via obligations required of owners of nuclear power plants. The Price-Anderson Act Amendment of 1988 allows for an inflationary provision adjustment every five years. Dominion and Virginia Power have purchased $300 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:
(1) Coverage for each unit exceeds the NRC minimum requirement.
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 the Nuclear Electric Insurance Limited (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 assessment for the current policy period is $95 million and $49 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 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 assessment for the current policy period is $33 million and $19 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
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 pro -
Combined Notes to Consolidated Financial Statements, Continued
vided by the Nuclear Waste Policy Act and by the Companies’ contracts with the DOE. In January 2004, Dominion and Virginia Power filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. A trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. On October 15, 2008, the Court issued an opinion and order for Dominion in the amount of approximately $155 million, which includes approximately $112 million in damages incurred by Virginia Power for spent fuel-related costs at its Surry and North Anna power stations and approximately $43 million in damages incurred for spent nuclear fuel-related costs at Dominion’s Millstone power station through June 30, 2006. Judgment was entered by the Court on October 28, 2008. In December 2008, the government appealed the judgment to the U. S. Court of Appeals for the Federal Circuit and the appeal was docketed. In March 2009, the Federal Circuit granted the government’s request to stay the appeal. With the exception of one case, the Federal Circuit has issued such stays in all other currently pending appeals from spent fuel damage awards. In November 2009, Dominion and Virginia Power filed a motion to lift the stay and the government has opposed this motion. Once the stay is lifted, briefing on the appeal will take place. Payment of any damages will not occur until the appeal process has been resolved. Dominion and Virginia Power cannot predict the outcome of this matter; however, in the event that they recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on their results of operations. A lawsuit was also filed for Dominion’s Kewaunee power station, and that lawsuit is presently stayed through March 15, 2010. The Companies will continue to manage their spent fuel until it is accepted by the DOE.
Guarantees, Surety Bonds and Letters of Credit
DOMINION
At December 31, 2009, Dominion had issued $261 million of guarantees to support third parties and equity method investees (issued guarantees). This includes $182 million of guarantees to support Dominion’s investment in a joint venture with Shell to develop NedPower. These NedPower guarantees are primarily comprised of a limited-scope guarantee and indemnification for one-half of the project-level financing for phases one and two of the NedPower wind farm, which would require Dominion to pay one-half of NedPower’s debt, only if it is unable to do so, as a direct result of an unfavorable ruling associated with current litigation seeking to halt the project. In February 2010, the underlying litigation was dismissed by the applicable court pursuant to an agreed dismissal order, and Dominion is in the process of seeking a formal acknowledgement from NedPower’s lenders that the termination provisions of Dominion’s litigation guaranty agreement have been satisfied. No significant amounts have been recorded. Dominion’s exposure under this litigation-related guarantee totaled $156 million as of December 31, 2009. Shell has provided an identical guarantee for the other one-half of NedPower’s borrowings.
Issued guarantees also include $21 million of guarantees to support Dominion’s investment in a joint venture with BP to develop Fowler Ridge. The guarantees primarily relate to certain
reserve requirements associated with Fowler Ridge’s non-recourse financing. Dominion’s exposure under these guarantees was $21 million as of December 31, 2009. BP has provided identical guarantees for the other one-half of these joint venture commitments.
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, 2009, Dominion’s maximum remaining cumulative exposure under these equity funding agreements is $156 million through 2019 and its maximum annual future contributions could range from approximately $14 million to $19 million. Dominion expects the operating cash flows for these projects to be sufficient to meet its 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. Dominion 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, 2009, Dominion had issued the following subsidiary guarantees:
(1) Represents the estimated portion of the guarantee’s stated limit that is utilized as of December 31, 2009 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, 2009, Dominion had purchased $151 million of surety bonds and authorized the issuance of standby letters of credit by financial institutions of $204 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, 2009, Virginia Power had issued $16 million of guarantees primarily to support tax exempt debt issued through conduits. Virginia Power had also purchased $89 million of surety bonds for various purposes, including providing workers’ compensation coverage. 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, 2009, 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.
Litigation
GAS AND OIL OPERATIONS
Dominion has been involved in litigation since 2006 with certain royalty owners seeking to recover damages as a result of Dominion allegedly underpaying royalties by improperly deducting post-production costs and not paying fair market value for the gas produced from their leases. The plaintiffs sought class action status on behalf of all West Virginia residents and others who are parties to, or beneficiaries of, oil and gas leases with Dominion. In 2008, the Court preliminarily approved settlement of the class action and conditionally certified a temporary settlement class. Following preliminary approval by the Court, settlement notices were sent out to potential class members. In 2009, the Court entered a Memorandum Opinion and Final Order approving settlement and certifying the settlement class and the Final Judgment Order. In 2007, Dominion established a litigation reserve representing its best estimate of the probable loss related to this matter and does not believe that final resolution of the matter will have a material adverse effect on its results of operations or financial condition.
ELECTRIC UTILITY OPERATIONS
Virginia Power is a co-owner with ODEC of the Clover power station. Virginia Power has been in litigation with Norfolk
Southern Railway Company (Norfolk Southern) regarding a long term coal transportation agreement for the delivery of coal to the facility. The trial court agreed with Norfolk Southern’s interpretation that the agreement specifies the use of an index (NS Index) which Norfolk Southern claims should have been applied to adjust the base rate and which should be applied going forward. The trial court assessed damages of approximately $78 million for the contract period from December 1, 2003 through November 30, 2007 and imposed prejudgment interest of approximately $9 million. Virginia Power’s share would have been one-half of the total judgment, or approximately $44 million. On appeal, the Supreme Court of Virginia in September 2009 affirmed the decisions of the trial court on all issues except for the calculation of damages. The Supreme Court of Virginia remanded the case to the trial court to recalculate damages in accordance with its opinion and in November 2009, the Circuit Court of Halifax County, Virginia entered a final order calculating damages and prejudgment interest through September 30, 2009 of approximately $11 million, of which Virginia Power has paid its one-half share.
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, 2009 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 geographic 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
Combined Notes to Consolidated Financial Statements, Continued
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, 2009, Dominion’s gross credit exposure totaled $753 million. After the application of collateral, credit exposure is reduced to $650 million. Of this amount, investment grade counterparties, including those internally rated, represented 94%. Two counterparty exposures are greater than 10% of Dominion’s total exposure, one representing 13% and the other 10%, both of which are large financial institutions 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, 2009, Virginia Power’s gross credit exposure totaled $39 million. After the application of collateral, credit exposure is reduced to $28 million. Of this amount, investment grade counterparties, including those internally rated, represented 82%, and no single counterparty exceeded 33%.
CREDIT-RELATED CONTINGENT PROVISIONS
The majority of Dominion’s and certain of Virginia Power’s derivative instruments contain credit-related contingent provisions. These provisions require the Companies 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, 2009, Dominion and Virginia Power would be required to post an additional $36 million and $2 million, respectively, of collateral to their 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. As of December 31, 2009, Dominion has posted $62 million in collateral, including $48 million of letters of credit and Virginia Power has not posted any collateral, 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, 2009 is $181 million for Dominion and $2 million for Virginia Power and 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.
In 2007, DCI had impairment losses associated with DCI operations of $98 million ($67 million after-tax) related to its investments in retained interests from CMO securitizations, loans held for resale and venture capital and other equity investments.
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. Virginia Power designates the majority of these contracts as cash flow hedges for accounting purposes.
DRS provides accounting, legal, finance and certain administrative and technical services to Virginia Power. In addition, Virginia Power provides certain services to affiliates, including charges for facilities and equipment usage.
Presented below are significant transactions with DRS and other affiliates:
During 2009, Virginia Power purchased turbines from an affiliate for $58 million to be used in the Bear Garden power station, currently under construction.
In September 2008, Virginia Power purchased a gas-fired turbine from an affiliate for $36 million as part of an expansion at its Ladysmith power station (Unit 5) to supply electricity during periods of peak demand.
The following table presents Virginia Power’s borrowings from Dominion under short-term arrangements:
In 2008, Virginia Power merged with Dominion Nuclear North Anna as part of continued development efforts associated with the possible construction of a third nuclear unit at North Anna. This merger was approved by the Virginia and North Carolina Commissions and became effective in December 2008. As a result of the merger, Virginia Power recorded assets and liabilities of $48 million, primarily reflecting the acquisition of an Early Site Permit and an in-process COL, and a payable to an affiliate that was settled in 2009.
Virginia Power incurred interest charges related to its borrowings from Dominion of $5 million, $10 million, and $27 million in 2009, 2008 and 2007, respectively.
In 2009, Virginia Power issued 31,877 shares of its common stock to Dominion reflecting the conversion of $1 billion of short-term demand note borrowings from Dominion to equity. In 2008, Virginia Power issued 11,786 shares of its common stock to Dominion reflecting the conversion of $350 million of short-term demand note borrowings from Dominion to equity. In 2007, Virginia Power recorded contributed capital of $220 million reflecting the conversion of a $220 million note payable to Dominion to equity.
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:
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 certain operations disposed of or to be disposed of, which are discussed in Note 5 to the Consolidated Financial Statements. Operations to be disposed of at December 31, 2009 include Peoples, which Dominion sold in February 2010. Operations disposed of during 2008 included certain DCI operations. Operations disposed of during 2007 included all of Dominion’s non-Appalachian E&P operations, three natural gas-fired merchant generation peaker facilities and certain DCI operations. 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.
Prior to the fourth quarter of 2009, Hope was included in Dominion’s Corporate and Other segment and its assets and liabilities were classified as held for sale. During the fourth quarter of 2009, following Dominion’s decision to retain this subsidiary, Hope was transferred to the Dominion Energy operating segment and its assets and liabilities were reclassified from held for sale. All segment information for prior years has been recast to conform to the new segment structure.
Combined Notes to Consolidated Financial Statements, Continued
DOMINION
In 2009, Dominion reported net expenses of $677 million in the Corporate and Other segment attributable to its operating segments. The net expenses 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;

A $712 million ($435 million after-tax) charge in connection with the proposed settlement of Virginia Power’s 2009 rate case proceedings, attributable to:

Dominion Generation ($257 million after-tax); and

DVP ($178 million after-tax); and

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, attributable to Dominion Generation.
In 2008, Dominion reported net expenses of $137 million in the Corporate and Other segment attributable to its operating segments. The net expenses in 2008 primarily related to the impact of the following items attributable to Dominion Generation:

$180 million ($109 million after-tax) of certain 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; and

$39 million ($24 million after-tax) of impairment charges related to non-refundable deposits for certain generation-related vendor contracts.
In 2007, Dominion reported net expenses of $618 million in the Corporate and Other segment attributable to Dominion’s operating segments. The net expenses in 2007 primarily related to the impact of the following items attributable to Dominion Generation:

A $387 million ($252 million after-tax) charge related to the impairment of Dresden;

A $259 million ($158 million after-tax) extraordinary charge due to the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s utility generation operations; and

A $231 million ($137 million after-tax) charge resulting from the termination of the long-term power sales agreement associated with State Line.
Intersegment sales and transfers are based on underlying contractual arrangements and agreements and may result in intersegment profit or loss.
The following table presents segment information pertaining to Dominion’s operations:
At December 31, 2009, 2008, and 2007, 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 2009, Virginia Power’s Corporate and Other segment included $430 million of net after-tax expenses attributable to its operating segments. The net expenses in 2009 primarily related to
a $700 million ($427 million after-tax) charge in connection with the proposed settlement of the 2009 rate case proceedings, attributable to Dominion Generation ($257 million after-tax) and DVP ($170 million after-tax).
In 2008, Virginia Power’s Corporate and Other segment included $23 million of net after-tax expenses attributable to its Dominion Generation segment. The net expenses in 2008 primarily related to impairment charges of $18 million ($11 million after-tax) related to non-refundable deposits for certain generation-related vendor contracts and $8 million ($5 million after-tax) reflecting other-than-temporary declines in the fair value of securities held as investments in nuclear decommissioning trusts.
Combined Notes to Consolidated Financial Statements, Continued
In 2007, Virginia Power’s Corporate and Other segment included $166 million of net after-tax expenses attributable to its Dominion Generation segment. The net expenses in 2007 largely resulted from a $259 million ($158 million after-tax) extra -
ordinary charge in connection with the reapplication of accounting guidance for cost-based regulation to the Virginia jurisdiction of Virginia Power’s generation operations.
The following table presents segment information pertaining to Virginia Power’s operations:
NOTE 28. GAS AND OIL PRODUCING ACTIVITIES (UNAUDITED)
In 2007, Dominion sold its non-Appalachian E&P operations. Dominion’s remaining Appalachian E&P operations do not qualify as significant gas and oil producing activities for 2009 or 2008. As a result, the following information only details Dominion’s gas and oil operations for 2007.
Total Costs Incurred
The following costs were incurred in gas and oil producing activities:
(1) Development costs incurred for proved undeveloped reserves were $445 million for 2007.
Results of Operations
Dominion cautions that the following standard disclosures required by the FASB do not represent its results of operations based on its historical financial statements. In addition to requiring different determinations of revenue and costs, the disclosures exclude the impact of interest expense and corporate overhead.
Company-Owned Reserves
Estimated net quantities of proved gas and oil (including condensate) reserves in the U.S. and Canada at December 31, 2007, and changes in the reserves during the year, is shown in the two schedules that follow:
(1) Natural gas liquids revisions were primarily the result of additional contractual changes with third-party gas processors in which Dominion now takes title to its processed NGLs, and residue gas and liquids reserve amounts recognized under such contracts. Oil/condensate revisions were primarily the result of positive performance revisions at Gulf of Mexico deepwater locations.
(2) Ending reserves included 0.3 million barrels of oil/condensate and 12.3 million barrels of NGLs.
Standardized Measure of Discounted Future Net Cash Flows and Changes Therein
The following tabulation has been prepared in accordance with the FASB’s rules for disclosure of a standardized measure of discounted future net cash flows relating to proved gas and oil reserve quantities that Dominion owns:
(1) Amounts exclude the effect of derivative instruments designated as hedges of future sales of production at December 31, 2007.
In the foregoing determination of future cash inflows, sales prices for gas and oil were based on contractual arrangements or market prices at December 31, 2007. Future costs of developing and producing the proved gas and oil reserves reported were based on costs determined at December 31, 2007, assuming the continuation of existing economic conditions. Future income taxes were computed by applying the December 31, 2007 statutory tax rate to future pretax net cash flows, less the tax basis of the properties involved, and giving effect to tax deductions, permanent differences and tax credits.
It is not intended that the FASB’s standardized measure of discounted future net cash flows represent the fair market value of Dominion’s proved reserves. Dominion cautions that the disclosures shown are based on estimates of proved reserve quantities and future production schedules which are inherently imprecise and subject to revision, and the 10% discount rate is arbitrary. In addition, costs and prices as of the measurement date are used in the determinations, and no value may be assigned to probable or possible reserves.
Combined Notes to Consolidated Financial Statements, Continued
The following tabulation is a summary of changes between the total standardized measure of discounted future net cash flows at the beginning and end of 2007:
NOTE 29. 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, 2009 and 2008 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
(1) Amounts attributable to Dominion’s common shareholders.
(2) Loss from discontinued operations had no impact on basic or diluted EPS.
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 proposed settlement of Virginia Power’s 2009 rate case proceedings.
Dominion’s 2008 results include the impact of the following significant items:

First quarter results include a $136 million after-tax benefit due to the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope. Results also include a $38 million after-tax charge resulting from the impairment of a DCI investment.

Third quarter results include a $26 million after-tax adjustment to the gain from the disposition of Dominion’s U.S. non-Appalachian E&P operations.

Fourth quarter results include after-tax charges of $58 million reflecting other-than-temporary declines in the fair value of certain securities held as investments in nuclear decommissioning trusts and a $24 million after-tax impairment charge related to non-refundable deposits for certain generation-related vendor contracts.
VIRGINIA POWER
Virginia Power’s quarterly results of operations were as follows:
Virginia Power’s 2009 results include the impact of the following significant item:

Fourth quarter results include a $427 million after-tax charge in connection with the proposed settlement of its 2009 rate case proceedings.
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 2009 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, 2009, 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.
Dominion evaluated its internal control over financial reporting as of December 31, 2009. 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, Dominion believes that it maintained effective internal control over financial reporting as of December 31, 2009.
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 26, 2010
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, 2009, 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, 2009, 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, 2009 of Dominion and our report dated February 26, 2010, expressed an unqualified opinion on those financial statements and includes an explanatory paragraph relating to the adoption of a new accounting standard.
/s/ Deloitte & Touche LLP
Richmond, Virginia
February 26, 2010
Item 9A(T). Controls and Procedures
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 2009 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, 2009, Virginia Power makes the following assertion:
Management is responsible for establishing and maintaining effective internal control over financial reporting of Virginia Power.
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.
Virginia Power evaluated its internal control over financial reporting as of December 31, 2009. 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, Virginia Power believes that it maintained effective internal control over financial reporting as of December 31, 2009.
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 was not subject to attestation by Virginia Power’s independent registered public accounting firm pursuant to temporary rules of the SEC that permit Virginia Power to provide only management’s report in this annual report.
Since management’s assessment is required without a report by the company’s independent registered public accounting firm regarding internal control over financial reporting, management’s report will be considered to be “furnished” rather than “filed” and therefore not subject to liability under Section 18 of the Exchange Act.
February 26, 2010
Item 9B. Other Information
Explanatory Note: The following information is provided here in lieu of filing a Form 8-K that would otherwise have been filed under Item 5.03 for events occurring on February 26, 2010.
Effective February 26, 2010, the Board of Directors of Dominion adopted amendments to its Bylaws in order to restate and implement Article X, Shareholder Proposals. This section was amended to specify additional information required to be provided by a shareholder who wishes to present shareholder proposals before the Annual Meeting of Shareholders and to clarify the manner in which those matters can be submitted. The full text of the Amendment is filed herewith as Exhibit 3.2.a.1.
Part III
Item 10. Directors, Executive Officers and Corporate Governance
DOMINION
The following information for Dominion is incorporated by reference from the 2010 Proxy Statement, File No. 001-08489, which will be filed on or around March 31, 2010 (the 2010 Proxy Statement):

Information regarding the directors required by this item is found under the heading Election of Directors.

Information regarding compliance with Section 16 of the Exchange Act required by this item is found under the heading Section 16(a) Beneficial Ownership Reporting Compliance.

Information regarding Dominion’s Audit Committee Financial expert(s) required by this item is found under the headings Director Independence and Committees and Meeting Attendance.

Information regarding Dominion’s Audit Committee required by this item is found under the headings The Audit Committee Report and Committees and Meeting Attendance.

Information regarding Dominion’s Code of Ethics required by this item is found under the heading Corporate Governance and Board Matters.
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 the Registrant.
VIRGINIA POWER
Information concerning directors of Virginia Power, each of whom is elected annually, is as follows:
(1) Any service listed for Dominion, DRS and CNG reflects service at a parent, subsidiary or affiliate. Virginia Power is a wholly-owned subsidiary of Dominion. DRS is an affiliate of Virginia Power and is also a subsidiary of Dominion. CNG is a former subsidiary of Dominion that merged with and into Dominion.
Section 16(a) Beneficial Ownership Reporting Compliance
To Virginia Power’s knowledge, for the fiscal year ended December 31, 2009, all Section 16(a) filing requirements applicable to its executive officers and directors were satisfied.
Audit Committee Financial Experts
Virginia Power is a wholly-owned subsidiary of Dominion. As permitted by SEC rules, its Board of Directors serves as the Company’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.
Information concerning the executive officers of Virginia Power, each of whom is elected annually is as follows:
(1) Any service listed for Dominion, DRS and CNG reflects services at a parent, subsidiary or affiliate.
Code of Ethics
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 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 at: 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.
Item 11. Executive Compensation
Dominion
Dominion’s information is contained in the 2010 Proxy Statement and is incorporated by reference: the information regarding executive compensation contained under the headings Compensation Discussion and Analysis and Executive Compensation; the information regarding Compensation Committee interlocks contained under the heading Compensation Committee Interlocks and Insider Participation; the Compensation, Governance and Nominating Committee Report; and the information regarding director compensation contained under the heading Non-Employee Director Compensation.
Virginia Power
COMPENSATION DISCUSSION AND ANALYSIS
Virginia Power is a wholly-owned subsidiary of Dominion. Virginia Power’s Board is comprised of Messrs. Farrell, McGettrick and Rogers. Messrs. Farrell and McGettrick are not
independent because they are executive officers of Virginia Power. Mr. Rogers is not deemed independent because of his employment with Dominion. Virginia Power’s Board believes that it is more appropriate for its compensation program to be managed under the direction of individuals who are independent and, therefore, Virginia Power does not have a compensation committee. Instead, Virginia Power’s board depends on the advice and recommendations of Dominion’s CGN Committee, which is comprised of independent directors and which retained the consulting firm of PM&P to advise the committee on compensation 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 successful performance is measured, evaluated and rewarded. It also describes Dominion’s compensation decision-making process. 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 2009, Virginia Power’s NEOs were:

Thomas F. Farrell II, Chairman and CEO

Mark F. McGettrick, Executive Vice President and CFO

Thomas N. Chewning, Executive Vice President and CFO (retired June 1, 2009)

Paul D. Koonce, President and COO - DVP

David A. Christian, President and COO - Generation

David A. Heacock, President and CNO
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. These aggregate amounts are reported in the Summary Compensation Table (and related tables) in Dominion’s annual proxy statement. For purposes of reporting each NEO’s compensation from Virginia Power in the Summary Compensation Table (and the 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 2010 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 health 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 compensation decisions. To determine if Dominion is meeting the objectives of the compensation program, the CGN Committee reviews and compares Dominion’s actual performance to short-term and long-term goals, its strategies and performance at Dominion’s peer companies.
Dominion’s 2009 performance indicates that the design of the compensation program is meeting these objectives. The NEOs have service with Dominion ranging from 11 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 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 conducts a comprehensive assessment and analysis of the executive compensation program, including each NEO’s compensation, with input from management and the independent compensation consultant. As part of the 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 CGN Committee meetings as requested by the chairman of the committee, either in person or by teleconference. The consultant also communicates directly with the chairman of the committee outside of meetings. PM&P provided the following services related to the 2009 executive compensation program:

performed a detailed review of base salary plus annual bonus potential (total cash compensation), the value of targeted long-term incentives, and total direct compensation (the sum of total cash and targeted long-term incentive compensation) for the NEOs, and provided a full report to the CGN Committee on its findings;

participated in the selection of the peer companies, providing independent advice to the CGN Committee on the process used to select the peer group and the appropriateness of the 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 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 projects, best practices and other matters.
MANAGEMENT’S ROLE IN THE 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.
Dominion’s internal compensation specialists provide the CGN Committee 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. Working with the CEO, the CFO and his team, and others, the internal compensation 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 CEO typically does not make any recommendations with respect to his own compensation. In early 2009, however, he made a request that the CGN Committee not consider any increase in his compensation for 2009.
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 2009 peer group was a diversified group consisting of the following 14 energy companies:
Ameren Corporation
FirstEnergy Corp.
American Electric Power Company, Inc.
FPL Group, Inc.
Constellation Energy Group, Inc.
NiSource, Inc.
DTE Energy Company
PPL Corporation
Duke Energy Corporation
Progress Energy, Inc.
Entergy Corporation
Public Service Enterprise Group Inc.
Exelon Corporation
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 the 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 the 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. As of year-end 2009, Dominion ranked above the peer market median in market capitalization, assets and revenues.
SURVEY DATA
Historically, PM&P and management have considered survey data in addition to peer company data to establish blended market benchmarks for the NEO positions. For 2009 compensation decisions, however, PM&P and management reviewed broad-based and industry-specific survey compensation data only for general purposes to obtain a general understanding of compensation practices. Due to the volatile and uncertain market conditions during the period that survey data was compiled, Dominion did not believe it was appropriate to benchmark or otherwise use market data or peer group data as the basis for 2009 compensation decisions.
COMPENSATION DESIGN AND RISK
The CGN Committee, with the assistance of 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 compensation may increase or mitigate risk-taking;

analysis of performance metrics used for annual and long-term incentive programs and the relation of such incentives to the objectives of a particular position or business unit;

analysis of whether the performance measurement periods for short-term and long-term incentive compensation are appropriate;

analysis of the overall structure of compensation programs as related to business risks; and

an annual review of Dominion’s share ownership guidelines, including share ownership levels and retention practices.
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. In addition, as described in Recovery of Incentive Compensation, the
CGN Committee’s authority to recover or “clawback” performance-based compensation deters excessive risk-taking and other performance-related misconduct. Other aspects of the compensation program deter excessive risk-taking, such as the requirement that payouts of performance grants for officers who retire are based on actual performance determined at the end of the performance period; strong share ownership guidelines; and prohibitions on hedging, pledging, and other derivative transactions related to Dominion stock.
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 scenar -
ios; 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 the market 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.
ELEMENTS OF DOMINION’S COMPENSATION PROGRAM
The executive compensation program consists of four basic elements:
Pay Element
Primary Objectives
Key Features & Behavioral Focus
Base Salary
 Provide competitive level of fixed cash compensation for performing day-to-day responsibilities
 Attract and retain talent
 Targeted at market median with adjustments based on internal equity and other Company considerations
 Rewards individual performance and level of experience
Annual Incentive Plan
 Provide competitive level of at-risk cash compensation for achievement of short-term financial and operational goals
 Align short-term compensation with the annual budget, earnings goals, business plans and core values
 Cash payments based on achievement of annual financial and individual operating and stewardship goals
 Rewards achievement of annual financial goals for Dominion and business unit and individual goals selected to support longer-term strategies
Long-Term Incentive Program
 Provide competitive level of at-risk compensation for achievement of long-term performance goals
 Create long-term shareholder value
 Retain talent
 A combination of performance-based cash and restricted stock awards (for 2009, a 50/50 mix)
 Encourages and rewards officers for making decisions and investments that create long-term shareholder value as reflected in superior relative TSR, as well as achieving desired returns on invested capital and BVP
Employee and Executive Benefits
 Provide competitive retirement and other benefit programs that attract and retain highly-qualified individuals
 Provide competitive terms to encourage officers to remain with Dominion during any potential change in control to ensure an orderly transition of management
 Dominion-wide benefit programs, supplemented by executive retirement plans, limited perquisites, and change in control and other agreements
 Encourages officers to remain with Dominion long-term and to act in the best interest of shareholders, even during any potential change in control
Factors in Setting Compensation
In setting compensation for 2009, Dominion did not follow the same process it has followed in recent years due to volatile market conditions and budget considerations. Instead of evaluating compensation for each officer on an individual basis and in comparison to market benchmarks, Dominion provided the same base salary increase of 2.5% for most officers and maintained its 2008 annual and long-term incentive target levels. There were a few exceptions, including for two of the NEOs. Mr. Farrell did not receive any increase in his compensation in 2009. An adjustment to Mr. Christian’s annual incentive target for reasons other than market-based pay considerations is described below in Annual Incentive Plan.
As part of the process of setting compensation targets, approving payouts and designing future programs, the CGN Committee evaluates Dominion’s overall performance versus its business plans and strategies, its short-term and long-term goals and as
compared to its peer companies. In addition to considering Dominion’s overall performance for the year, the CGN Committee takes into consideration several individual factors that are not given any specific weighting in setting each element of compensation for each NEO, including:

an officer’s experience and job performance;

the scope of responsibility for a position, including any differences from peer company positions and general market survey data;

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 plans for other key positions.
Generally, in prior years the compensation program has been designed to pay base salary and total cash compensation at or slightly above the 50th percentile for the officers as a group. Total direct compensation for officers as a group has been designed to be in a range between the 50th and 75th percentiles, but actual achievement of the incentive-based compensation goals will determine what is actually earned. As part of this analysis, Dominion has taken into account its larger size and complexity compared with its peer companies. However, as discussed above comparative data was not a factor in setting compensation for 2009.
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 Dominion (as compared to the other NEOs who are responsible for significant but distinct areas within Dominion) 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 versus the next highest-paid officer and 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 the ratios to that of the peers to confirm that the 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 the peers. The CGN Committee did not make any adjustments to the compensation of any NEOs based on this review in 2009.
Allocation of Total Direct Compensation in 2009
Consistent with the 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 86% of Mr. Farrell’s targeted 2009 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 64% to 77% of targeted 2009 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 2009 for Mr. Farrell and the other NEOs as a group (excluding Mr. Chewning who retired June 1, 2009) and the allocation of such compensation among base salary, targeted 2009 AIP award and targeted 2009 long-term incentive compensation.
Base Salary
Base salary compensates officers, along with the rest of the workforce, 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 market 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 Dominion executives and other relevant considerations.
Although the base salary component of the program generally is targeted at or slightly above market median, the primary goal is to compensate the officers at a level that best achieves Dominion’s objectives and reflects the considerations discussed above. Dominion finds that market data resources for particular positions can vary greatly from year to year; therefore, Dominion considers market trends for certain positions over a period of years rather than a one-year period in setting base salaries for such positions. Dominion believes that an overall goal of targeting base salary at or slightly above the market median is a conservative but appropriate target for base pay. In addition to being above the peer group market median in 2009 in terms of market
capitalization, assets and revenues, Dominion’s business operations are 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 below market median, or in the case of Dominion’s nuclear officers, below levels closer to the 75th percentile.
As explained above, Dominion did not use market data as the basis for 2009 compensation decisions. Individual and Company performance would have supported merit increases for 2009 of 3.5% or more for the NEOs, but due to uncertain market conditions and the current economic climate, the CGN Committee capped merit base salary increases at 2.5% for most officers, including the NEOs. At Mr. Farrell’s request, the CGN Committee set his 2009 base salary at the same level as 2008.
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. All non-union employees (including the NEOs) scheduled to work 1,000 hours or more in a calendar year are eligible to participate in the AIP. Union employees covered under collective bargaining agreements that provide for participation in an annual incentive plan are also eligible to participate in the AIP.
The AIP 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 group 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 his 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.
In prior years, the AIP target awards established for the NEOs and other officers were generally designed so that an officer’s total cash compensation for the year would be at or slightly above the market median if the plan goals and full funding are achieved. For
nuclear officers as a group, Dominion targeted compensation that was more consistent with market 75th percentile overall in recognition of the significant size and outstanding performance of the nuclear unit, competition in that industry, and the unique skills and experience that the nuclear officers contribute to that critical area of the business strategy. Annual incentive target award levels were also consistent with the intent to have a significant portion of NEO compensation at risk.
If AIP goals are exceeded, as they were in 2009, an officer’s total cash compensation may be higher than market median depending on the extent to which goals are exceeded, and if the goals are not achieved, an officer’s total cash compensation may be significantly lower than market median depending on the extent to which goals are not achieved. Dominion does not, however, review comparative data at the end of the performance period to determine the extent to which AIP payouts may be above or below market median because the intent is to pay for actual performance at Dominion.
As explained above, 2009 AIP targets as a percentage of base salary generally were maintained at 2008 levels. The 2009 AIP targets for the NEOs, as a percentage of their base salary, were: Mr. Farrell - 125%; Mr. McGettrick - 95%; Mr. Chewning - 95%; Mr. Koonce - 90%; Mr. Christian - 80%; and Mr. Heacock - 70%. Based on internal pay equity considerations, including the relative importance of Mr. Christian’s position at the time, as well as succession planning considerations, the CGN Committee increased the AIP target for Mr. Christian from 70% to 80% in 2009 while Mr. Christian was the CNO; he was promoted to CEO - Dominion Generation on June 1, 2009.
FUNDING OF THE 2009 AIP
Funding of the 2009 AIP was based solely on consolidated operating EPS, with potential funding ranging from 0% to 200% of the target funding. Consolidated operating EPS 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 EPS targets, Dominion increases employee awareness of the Company’s financial objectives and encourages behavior and performance that will help achieve these objectives.
The 2009 AIP had a full funding target of $3.25 operating EPS for Dominion, the approximate mid-point of Dominion’s 2009 earnings guidance announced in January 2009, or $1.92 billion in consolidated operating earnings. Funding is based on a formula that provides proportionate sharing of consolidated operating earnings between AIP participants and Dominion shareholders until the full funding target is achieved. Consolidated operating earnings above the full funding target of $3.25 operating EPS are shared equally with shareholders, up to the maximum AIP funding level of 200% at $3.37 operating EPS.
Full funding means that the AIP is 100% funded and part-icipants 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, 2009 were $1.94 billion or $3.27 per share as compared to its consolidated reported earnings in accordance with GAAP of $1.29 billion or $2.17 per share.* This resulted in 116% funding for the 2009 AIP.
*Reconciliation of 2009 Consolidated Operating Earnings to Reported Earnings. The following items, which are net of tax, are included in Dominion’s 2009 reported earnings, but are excluded from consolidated operating earnings: $281 million impairment charge related to gas and oil properties, $435 million charge for proposed Virginia base rate case settlement, $62 million benefit related to revision of a nuclear decommissioning ARO for a power station no longer in service, $26 million of earnings from Peoples and $27 million net expense related to other items.
HOW AIP PAYOUTS ARE DETERMINED
For most officers, payout of their funded AIP awards for 2009 was subject to the accomplishment of business unit financial and operating and stewardship goals, including a required safety goal. The percentage allocated to each category of goals represents the percentage of the funded award subject to the performance 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). Code Section 162(m) requires (i) that performance goals be established during the initial 90 days of the performance period and (ii) that the goals are not altered during the performance period. To preserve the tax deduction for payouts made to the NEOs, 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 2009 AIP, all of the NEOs adopted a discretionary safety goal. Messrs. Koonce, Christian and Heacock adopted discretionary business unit financial goals, and Mr. Heacock also adopted discretionary operating and stewardship goals. These goals are described under 2009 AIP Payouts. The table below shows the goal weightings applied to these discretionary goals.
* 5% goal weighting shown is for a safety goal. Mr. Heacock had other, non-safety operating and stewardship goals, as described below.
2009 AIP PAYOUTS
The formula for calculating an award is:
The 2009 discretionary business unit financial goals and accomplishment levels for Mr. Koonce (DVP) and Mr. Christian and Mr. Heacock (Dominion Generation) were as follows:
All business units worked together to modify their 2009 budgets in support of the consolidated 2009 budget plan. DVP and Dominion Generation would have fully achieved their net income goals if their respective budgets had not been modified. Accordingly, the CGN Committee determined it was appropriate not to exercise its negative discretion to reduce the 2009 AIP payouts for Messrs. Koonce, Christian and Heacock based on the actual accomplishment of the discretionary business unit financial
goals for DVP and Dominion Generation, respectively, that was below 100%.
All of the NEOs adopted a discretionary safety goal of minimizing OSHA recordable incident rates to a specified target number. Each NEO achieved his safety goal. In addition to his safety goal, which was weighted 9%, Mr. Heacock had goals in three other categories, weighted as indicated: Environmental Stewardship (weighted 6%); Capacity Factor (weighted 7.5%); and Production Cost (weighted 7.5%). Mr. Heacock’s Environmental Stewardship goal was to minimize the number of environmental performance points assessed at each of Dominion’s nuclear stations to a specified target number. This goal was not fully achieved with more points assessed than the targeted goal. Mr. Heacock’s Capacity Factor (CF) goal was to achieve or exceed a targeted CF percentage. CF, expressed as a percentage, is actual generation divided by projected generation. The CF goal was fully achieved. Mr. Heacock’s Production Cost goal was to cap these costs at targeted numbers and this goal was also fully achieved. Mr. Heacock earned four extra credit points for safety by exceeding his overall safety goal, but was not able to apply this to his Environmental Stewardship goal shortfall as this was a regulatory goal. As a result, his total payout score was 97.6%.
Amounts earned under the 2009 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 in the year presented.
* Due to Mr. Chewning’s retirement on June 1, 2009, his payout was pro-rated based on his five months of service during the 12-month performance period.
Long-Term Incentive Program
OVERVIEW
The long-term incentive program focuses on Dominion’s longer-term strategic goals and retention. In recent years, 50% of the 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 towards 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.
In prior years, the long-term incentive values for the NEOs and other officers were targeted between the market median and the 75th percentile, which is consistent with Dominion’s larger size and complexity compared with the peer companies. Actual performance versus pre-set performance goals determines the extent to which final long-term compensation earned is at, above, or below market median or market 75 th percentile. Consistent with Dominion’s intent to pay for actual achievement of the performance goals established at the beginning of the performance period, Dominion does not review comparative data at the end of the performance period to determine the extent to which payouts may be above or below market median or market 75th percentile. Additionally, an analysis of comparative data would be of little practical use due to factors such as job rotations and changes in market conditions during the performance cycle.
The fact that an officer may have received long-term incentive awards over the course of his or her career is not a significant consideration in determining the officer’s entitlement to appropriate long-term incentive awards in the current year. If a newer officer does not have prior grants outstanding due to his or her short tenure, Dominion does not increase the compensation paid to such officer due to a lack of outstanding grants from prior years.
2009 RESTRICTED STOCK GRANTS
All officers received a restricted stock grant on February 2, 2009 based on a stated dollar value. The 2009 restricted stock grants for NEOs had the same value as their 2008 restricted stock grants. The number of shares awarded was determined by dividing the stated dollar value by the closing price of Dominion’s common stock on January 30, 2009. The grants have a three-year vesting term, with cliff vesting at the end of the restricted period on February 1, 2012. Dividends are paid to officers during the restricted period. The grant date fair value of each NEO’s 2009 restricted stock grant is disclosed in the Grants of Plan-Based Awards table. Dividends paid during 2009 are reported in the All Other Compensation column of the Summary Compensation Table.
2009 PERFORMANCE GRANTS
Most officers, including the NEOs, received cash performance grants on February 2, 2009. The 2009 performance grant levels for NEOs were the same as their 2008 grant levels. Officers who have 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, 2009 and will end on December 31, 2010. Like the 2008 performance grants, the 2009 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, ROIC and BVP.
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 BVP metric is intended to promote better long-term value of Dominion’s assets by effective capital allocation and management and to encourage a decision-making process that minimizes write-offs and issuances of stock below anticipated share prices.
VESTING TERMS FOR THE 2009 RESTRICTED STOCK GRANTS AND PERFORMANCE GRANTS
The grants are forfeited in their entirety if an officer voluntarily terminates employment or is terminated with cause before the vesting date. The grants have pro-rated vesting for retirement, termination without cause, death or disability, which rewards the officers or their estate only for the period of time they provided services to Dominion. In the case of retirement, however, pro-rated vesting will not occur if Dominion’s CEO (or, for the CEO, the CGN Committee) determines the officer’s retirement is detrimental to the company.
For the performance grants, payout for an officer who retires or whose employment is terminated without cause is made following the end of the performance period so that the officer is rewarded only to the extent the performance goals are achieved. In the case of death or disability, payout is made as soon as possible to facilitate the administration of the officer’s estate or financial planning; the payout amount will be the greater of the officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements.
In the event of a change in control, Dominion uses a modified double trigger for the vesting of the restricted stock awards, with pro-rated vesting as of the change in control date, and full vesting if an officer’s employment is terminated (or constructively terminated) by the successor entity before the scheduled vesting date. This approach appropriately rewards officers for their service with Dominion up through the date of the change in control and also encourages them to remain with the successor entity to ensure an orderly transition of management following the change in control.
Dominion takes a different approach for performance grants. Given that the relative TSR, ROIC and BVP metrics are exclusively Dominion-related goals, Dominion does not consider it reasonable or fair to continue to apply those goals in the event of a change in control. Accordingly, the payout of the
performance grants will occur as soon as administratively feasible following the change in control date at an amount that is the greater of an officer’s target award or an amount based on the predicted performance used for compensation cost disclosure purposes in Dominion’s financial statements.
PAYOUT UNDER 2008 PERFORMANCE GRANTS
In February 2010, payouts were made to officers who received 2008 performance grants, including the NEOs. The 2008 performance grants were based on three goals: TSR for the two-year period ended December 31, 2009 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, 2009 (weighted 10%).

Relative TSR (50% weighting). TSR is the difference between the value of a share of Dominion’s 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 2008 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 for the 2008-2009 performance period were as follows:
* 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 2008-2009 performance period was in the second quartile.

ROIC (40% weighting). ROIC reflects Dominion’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 approved by Dominion’s Board. For this purpose, total return is Dominion’s consolidated operating earnings plus its after-tax interest and related charges, plus preferred dividends. The ROIC goals were designed to provide 100% payout if Dominion achieves an average ROIC of 8.70% over the two-year performance period. The ROIC performance targets and corresponding payout scores for the 2008-2009 performance period were as follows:
* ROIC percentage payout is interpolated between the top and bottom of the percentages for any range.
Actual ROIC performance for the 2008-2009 period was 8.81%.

BVP (10% weighting). BVP measures Dominion’s value according to its balance sheet (the difference between assets and liabilities) as opposed to the market value of Dominion 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, 2009. The BVP targets and corresponding payout scores as of December 31, 2009 were as follows:
* BVP percentage payout is interpolated between the top and bottom of the percentages for any range.
Actual BVP as of December 31, 2009 was below $20.50. Based on the achievement of the performance criteria, the CGN Committee approved a 126.4% payout for the 2008 performance grants. The following table summarizes the achievement of the 2008 performance criteria:
The resulting payout amounts for the NEOs for the 2008 Performance Grants are shown below and are also 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 in the year presented.
* Due to Mr. Chewning’s retirement on June 1, 2009, his payout was pro-rated based on his 14 months of service (measured from the April 2008 grant date) during the two-year performance period.
2010 Compensation Decisions
In January 2010, the CGN Committee approved the AIP and LTIP for 2010. There are no changes to the design of the AIP for 2010. The full funding target for the 2010 AIP is $3.30 operating EPS, the approximate mid-point of Dominion’s 2010 earnings guidance. Like the 2009 LTIP, 50% of the 2010 LTIP awards are full value equity awards in the form of restricted stock that will become vested after three years and 50% are performance-based awards with metrics measured over a two-year performance period. There are two metrics for the performance-based awards: relative TSR to the 2010 peer group (weighted 50%) and ROIC (weighted 50%). The TSR goals for 2010 are the same as those
described above for the 2008 performance-based awards. The ROIC goals have been updated to reflect Dominion’s 2010 - 2011 business and strategic plans. The grant date for the 2010 LTIP awards is February 1, 2010.
Employee and Executive Benefits
Benefit plans and limited perquisites comprise 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 and a defined contribution 401(k) savings 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 Dominion 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 NEOs participate in the DPP. The formula for the DPP is explained in the narrative following the Pension Benefits table. The change in pension plan value for 2009 for the NEOs is included in the Summary Compensation Table.
Officers whose matching contributions under the 401(k) plan are limited by Internal Revenue Code limits 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 for the officers, the BRP and the ESRP. 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. Because of Internal Revenue Code limits on pension plan benefits and because a more substantial portion of total compensation for the officers is paid as incentive compensation than for other employees, the DPP 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 DPP 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 from the Company. 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.
OTHER BENEFIT PROGRAMS
Dominion’s officers participate in all of the benefit programs available to other Dominion employees. The core benefit programs 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, and long-term disability coverage and a paid time off program. There are other miscellaneous employee benefit programs, including employee assistance programs and employee leave policies.
Dominion also maintains an Executive Life Insurance Program for officers to replace a former Dominion 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 perquisites for the 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 received 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 the vehicles are paid by Dominion.

In limited circumstances, use of Dominion 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 officer’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 2009, 96% of the use of Dominion’s aircraft was for business purposes. Other than Mr. Farrell, none of the NEOs or other executive officers used Company aircraft for personal travel in 2009.
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 Dominion 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 MATTERS
Mr. Chewning retired from Dominion on June 1, 2009. In accordance with the terms of the 2009 AIP, Mr. Chewning’s AIP payout was based on actual goal achievement determined after the end of the plan year and pro-rated for his five months of service during 2009. Mr. Chewning’s payout under his 2008 performance grant also was based on the actual goal achievement following the end of the performance period that ended December 31, 2009 and was pro-rated for his months of service during the performance period. Similarly, Mr. Chewning’s payout, if any, under his 2009 performance grant will be determined after the end of the performance period ending December 31, 2010 and will be pro-rated based on his months of service during the performance period that will end on December 31, 2010.
Mr. Chewning’s outstanding restricted stock awards under the 2007, 2008, and 2009 long-term incentive programs were vested pro-rata upon his retirement based on a determination that Mr. Chewning’s retirement would not be detrimental to the Company. Mr. Chewning’s 2008 restricted stock retention award
became fully vested upon Mr. Chewning’s retirement based on the CGN Committee’s determination that Mr. Chewning’s retirement would not be detrimental to the Company. The number of shares and value received upon vesting for these restricted stock awards are shown in the Options Exercised and Stock Vested table.
Pursuant to his February 2003 letter agreement with the Company, Mr. Chewning received a payment equal to his final annual base salary upon his retirement as consideration for his agreement not to compete with the Company for a two year period following his retirement. The amount of this non-compete payment is included in the All Other Compensation column of the Summary Compensation Table.
In September 2009, several months following his retirement, Dominion engaged Mr. Chewning as a consultant to testify in the Virginia base rate case proceeding, to provide support with other pending rate cases and to provide advice regarding strategic transactions, investor relations, financial matters and other matters as requested by Messrs. Farrell or McGettrick. Consulting fees paid to Mr. Chewning for his services are disclosed in the All Other Compensation column of the Summary Compensation Table.
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 five 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 the Company. Targeted ownership levels are the lesser of the following:
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 Dominion 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 derivative securities, hedging transactions, 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 Dominion. 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 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 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 Dominion’s 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 the 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 compen -
sation. 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.
Executive Compensation
SUMMARY COMPENSATION TABLE - AN
OVERVIEW
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, the former CFO and the three most highly compensated executive officers of Virginia Power other than the CEO and CFO.
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. Mr. Chewning retired on June 1, 2009 and Mr. McGettrick succeeded him as CFO effective as of that date. SEC rules require disclosure of Mr. Chewning’s compensation because he served as the company’s CFO for a portion of the year.
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 2009 was as follows: Mr. Farrell, 29%; Mr. McGettrick, 46%; Mr. Chewning, 42%; Mr. Koonce, 49%; Mr. Christian, 47%, and Mr. Heacock, 62%.
Salary. The amounts in this column are the base salaries earned by the NEOs for the years indicated.
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 and 2007 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 the LTIP. 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 Dominion, which include the DPP 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 the Dominion’s audited financial statements for the applicable fiscal year, including assumed retirement dates, life expectancy of the officers and other assumptions. For 2009, however, 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. 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 Dominion paid life insurance premiums, Dominion matching contributions to an NEO’s 401(k) Plan account, Dominion 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, payment for unused vacation days not carried forward to the following year, and dividends paid on 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.
SUMMARY COMPENSATION TABLE
The following table presents information concerning compensation paid or earned by the NEOs for the years ended December 31, 2009, 2008 and 2007 as well as the grant date fair value of stock awards and changes in pension value.
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 in the year presented.
(1) Mr. Farrell did not receive a salary increase in 2009. Salary increases for the other NEOs became effective on March 1, 2009. For the months of January and February 2009, monthly salary was paid at the 2008 monthly salary amount.
(2) The amounts in this column reflect the full grant date fair value of stock awards for the respective year, in accordance with FASB ASC Topic 718-guidance for share-based payments. Dominion did not grant any stock options in 2009. For Mr. Chewning, the amounts in the table reflect the full value of his awards as of the grant dates. He retired on June 1, 2009 and became vested in a pro-rata portion of his 2007, 2008, and 2009 restricted stock awards under the LTIP and 100% vested in his 2008 retention restricted stock award. See Note 20 to the Consolidated Financial Statements in Dominion’s 2009 Annual Report on Form 10-K for more information on the valuation of stock-based awards and the Outstanding Equity Awards at Fiscal Year-End table for a listing of all outstanding equity awards as of December 31, 2009.
(3) The 2009 amounts in this column include the payout under Dominion’s 2009 AIP and 2008 Performance Grant. All of the NEOs except Mr. Heacock received a 116% payout of their 2009 AIP target awards, reflecting 116% funding of the 2009 AIP and 100% accomplishment of their goals. Mr. Heacock’s payout was reduced by the CGN Committee due to 97.6% accomplishment of his goals. The 2009 AIP payout amounts were as follows: Mr. Farrell: $504,600; Mr. McGettrick: $329,954; Mr. Chewning: $134,516 (due to Mr. Chewning’s retirement on June 1, 2009, his payout was pro-rated based on his five months of service during the twelve-month performance period); Mr. Koonce: $254,706; Mr. Christian: $241,545; and Mr. Heacock: $158,021. See the CD&A for additional information on the 2009 AIP and the Grants of Plan Based Awards table for the range of each NEO’s potential award under the 2009 AIP. The 2008 Performance Grant was awarded on April 1, 2008 and the payout amount was determined based on achievement of performance goals for the 24-month performance period ended December 31, 2009. Payouts can range from 0% to 200% of the target amount. The actual payout was 126.4% of the target amount. The payout amounts were as follows: Mr. Farrell: $1,099,680; Mr. McGettrick: $436,080; Mr. Chewning: $353,920 (due to Mr. Chewning’s retirement on June 1, 2009, his payout was pro-rated based on his 14 months of service during the performance period); Mr. Koonce: $278,712; Mr. Christian: $193,076; and Mr. Heacock: $137,144. The 2008 amounts reflect both the 2008 AIP and the 2007 Performance Grant payouts, and the 2007 amounts reflect both the 2007 AIP and the 2006 Performance Grant payouts.
(4) All amounts in this column are for the aggregate change in the actuarial present value of the NEO’s accumulated benefit under the DPP and nonqualified executive retirement plans. In connection with his retirement on June 1, 2009, Mr. Chewning received payments from the pension plans, as shown in the Pension Benefits table, which resulted in a reduction in the present value of his accumulated benefits measured as of December 31, 2009 compared to those benefits as of December 31, 2008. There are no above-market earnings on nonqualified deferred compensation plans. The values shown in this column are not directly in relation to the actual pension benefits that will be payable upon each NEO’s retirement and can vary significantly year over year based on (i) interest rate and other actuarial assumptions; (ii) adjustments to salary or AIP targets; and (iii) actual age versus predicted age at retirement. For 2009, increases in pension values are partially attributable to the application of actuarial factors applied for purposes of determining eligibility for unreduced retirement benefits. See the narrative following the Pension Benefits Table for additional information regarding the actuarial assumptions used to calculate values in this column.
(5) All Other Compensation amounts for 2009 are as follows:
(a) Unless noted, the amounts in this column for all NEOs are comprised of the following: personal use of company vehicle and financial planning and health and wellness allowance. For Mr. Farrell, the amounts in this column also include personal use of the corporate aircraft. The value of Mr. Farrell’s personal use of the aircraft during 2009 was $14,790. For personal flights, all direct operating costs are included in calculating aggregate incremental cost. Direct operating costs include the following: fuel, airport fees, catering, ground transportation and crew expenses (any food, lodging and other costs). The fixed costs of owning the aircraft and employing the crew are not taken into consideration, as 96% of the use of the corporate aircraft is for business purposes. The CGN Committee has directed Mr. Farrell to use corporate aircraft for all personal travel whenever it is feasible to do so.
(b) Employees who contribute to the 401(k) Plan receive a matching contribution of 50 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have less than 20 years of service, and 67 cents for each dollar contributed up to 6% of compensation (subject to IRS limits) for employees who have 20 or more years of service.
(c) Represents each payment of “lost” 401(k) Plan matching contribution due to IRS limits.
(d) For 2009, all full-time employees could elect to sell up to 40 hours of vacation they did not use during the calendar year and receive the sold hours as taxable compensation. This practice was discontinued beginning January 1, 2010.
(e) Included in this amount is a lump sum payment of $292,955 paid to Mr. Chewning as consideration for a two-year non-compete agreement that was entered into on February 23, 2003, and $75,600 for consulting fees paid to Mr. Chewning for the period of September 2009 through December 2009. Following his retirement, Dominion entered into an agreement with Mr. Chewning to provide consulting services related to the pending rate cases, pending and potential transactions, investor relations, financial markets and other matters as requested by Messrs. Farrell or McGettrick.
GRANTS OF PLAN-BASED AWARDS TABLE
The following table provides information about stock awards and non-equity incentive awards granted to the NEOs during the year ended December 31, 2009.
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 in the year presented.
(1) On January 26, 2009, the CGN Committee approved the 2009 long-term compensation awards for the officers, which consisted of a restricted stock grant and a cash performance grant. The 2009 restricted stock award was granted on February 2, 2009. Under the 2005 Incentive Compensation Plan, fair market value is defined as the closing price of Dominion common stock as of the last day on which the stock is traded preceding the date of grant. The fair market value for the February 2, 2009 restricted stock grant was $35.18 per share, which was Dominion’s closing stock price on January 30, 2009.
(2) Amounts represent the range of potential payouts under the 2009 AIP. Actual amounts paid under the 2009 AIP are found in the Non-Equity Incentive Plan Compensation column of the Summary Compensation Table. Under the AIP, officers are eligible for an annual performance-based award. The CGN Committee establishes target awards for each NEO based on his salary level and expressed as a percentage of the individual NEO’s base salary. The target award is the amount of cash that will be paid if the plan is fully funded and payout goals are achieved. For the 2009 AIP, funding is based on the achievement of consolidated operating earnings goals with the maximum funding capped at 200%, as explained under the Annual Incentive Plan section of the CD&A. The 2009 target percentages of base salary for the NEOs are as follows: Mr. Farrell-125%; Messrs. McGettrick and Chewning-95%; Mr. Koonce-90%; Mr. Christian-80% and Mr. Heacock-70%. Due to Mr. Chewning’s retirement on June 1, 2009, he received a pro-rata payout of his 2009 AIP award based on his five months of service during 2009. This payout was made in February 2010 at the same time payouts were made to other officers and was calculated based on goal achievement for the one-year performance period.
(3) Amounts represent the range of potential payouts under the 2009 cash performance grant. Payouts can range from 0% to 200% of the target award. Awards will be paid in February 2011 depending on the achievement of performance goals for the two-year period ended December 31, 2010. The amount earned will depend on the level of achievement of three performance metrics: TSR-50%, ROIC-40% and BVP-10%. TSR measures Dominion’s share performance for the two-year period ended December 31, 2010 relative to the TSR of a group of industry peers selected by the CGN Committee. ROIC goal achievement will be scored against 2009 and 2010 budget goals. BVP will measure Dominion’s value according to its balance sheet (as opposed to the market value of company stock). Mr. Chewning’s retirement on June 1, 2009, any payout of his 2009 performance grant will be pro-rated based on his four months of service, measured from the February 2009 grant date, during the 24-month performance period.
(4) The 2009 restricted stock grant fully vests at the end of three years. The restricted stock grant provides for pro-rata vesting if an officer dies, becomes disabled, is terminated without cause or if there is a change in control. Pro-rated vesting will also occur upon retirement if the CEO of Dominion (or in the case of the CEO, the CGN Committee) determines the officer’s retirement is not detrimental to Dominion. Dividends on the restricted shares are paid during the restricted period at the same rate declared by Dominion for all shareholders. Due to Mr. Chewning’s retirement on June 1, 2009, he became vested in 1,326 shares of his 2009 restricted stock grant attributable to service performed for Virginia Power with a fair market value on the vesting date of $31.79 per share, which was Dominion’s closing stock price on May 29, 2009.
OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END
The following table summarizes equity awards made to NEOs that were outstanding as of December 31, 2009. There were no unexercised or unexercisable option awards outstanding for any of the NEOs as of December 31, 2009.
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 in the year presented.
(1) The market value is based on closing stock price of $38.92 on December 31, 2009.
(2) Shares scheduled to vest on April 3, 2010
(3) Shares scheduled to vest on April 1, 2011
(4) Shares scheduled to vest on February 1, 2012
(5) Upon his retirement on June 1, 2009, Mr. Chewning’s outstanding restricted stock awards vested in accordance with the terms of the award agreements.
OPTION EXERCISES AND STOCK VESTED
The following table provides information about the value realized by NEOs during the year ended December 31, 2009 on exercised stock options and vested restricted stock awards.
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 in the year presented.
PENSION BENEFITS(1)
The following table shows the actuarial present value of accumulated benefits payable to the 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, 2009, using the same interest rate and mortality assumptions used in determining the aggregate pension obligations disclosed in the company’s financial statements. Please refer to Actuarial Assumptions Used to Calculate Pension Benefits for detailed information regarding these assumptions.
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 in the year presented.
(1) The years of credited service and the present value of accumulated benefits were determined by the plan actuaries, using the appropriate accrued service and pay and other assumptions similar to those used for accounting and disclosure purposes.
(2) Years of credited service for the DPP are actual years accrued by an NEO from his date of participation to December 31, 2009. Service for the BRP and the ESRP is the NEO’s actual credited service as of December 31, 2009 plus any potential credited service to the plan maximum, including any extra years of credited service granted to Messrs. Farrell, McGettrick and Chewning by the CGN Committee for the purpose of calculating benefits under these plans. Please refer to the narrative below and under Potential Payments Upon Termination or Change In Control and Additional Post-Employment Benefits for information about the requirements for receiving extra years of credited service and the amount credited, if any, for each NEO.
(3) The amounts in this column are based on actuarial assumptions that all of the NEOs would retire at the earliest age they become eligible for unreduced benefits, which is (i) age 60 for Messrs. Farrell, Koonce, Christian and Heacock, and (ii) age 55 for Mr. McGettrick (when he would be treated as age 60 based on his five additional years of credited age). In addition, for purposes of calculating the BRP benefits for Messrs. Farrell and McGettrick, the amounts reflect additional credited years of service granted to them pursuant to their agreements with Dominion (see Additional Post-Employment Benefits for NEOs below). If the amounts in this column did not include the additional years of credited service, the present value of the BRP benefit would be $841,267 lower for Mr. Farrell and $1,097,047 lower for Mr. McGettrick. DPP and ESRP benefits amounts are not affected by the additional service credit assumptions.
Dominion Pension Plan
The DPP is a tax-qualified defined benefit pension plan. All of the NEOs participate in the DPP. The DPP 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 attaind 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 DPP 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 or 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 SRA, which is in addition to the pension benefit. The SRA is credited with 2% of base pay each month as well as interest based on the 30-year Treasury bond rate set annually (6.66% in 2009). The SRA 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 2009, 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 2009, 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 Dominion Retirement 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 pension plan and BRP benefits. Under the terms of a retention agreement, Mr. Chewning earned 30 years of credited service for purposes of calculating his 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’s benefit will be calculated based on five additional years of age and 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-Retirement Benefits for NEOs under Potential Payments Upon Termination or Change in Control.
If a 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 DPP and paid in a lump sum payment.
Dominion Executive Supplemental Retirement Plan
The Dominion 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. 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 ESRP 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 Messrs. and Mr. Heacock are currently entitled to a full ESRP retirement benefit. If Messrs. Koonce and Heacock terminate employment prior to age 55, they will receive pro-rated ESRP benefits. Based on determinations made by the CGN Committee, Mr. Farrell will receive an ESRP benefit calculated as a lifetime benefit, Messrs. McGettrick and Christian will receive ESRP benefits calculated as lifetime benefits provided they remain employed with the Company until attainment of age 60, and Mr. Koonce will receive a benefit calculated as a lifetime benefit if he remains employed with the Company until attainment of age 50.
Actuarial Assumptions Used to Calculate Pension Benefits
Actuarial assumptions used to calculate DPP benefits are prescribed by the terms of the pension plan 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, 2009 benefit calculations shown in the Pension Benefits table use a discount rate of 6.6% to determine the present value of the future benefit obligations for the DPP, BRP and ESRP and a lump sum interest rate of 5.85% 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 BRP 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 2009 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%.
NONQUALIFIED DEFERRED COMPENSATION
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 in the year presented.
* 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 Dominion officers and other highly compensated employees: The Dominion Resources, Inc. Executives’ Deferred Compensation Plan (Frozen Deferred Compensation Plan), and Dominion Resources, Inc. Security Option Plan (Frozen DSOP) were frozen as of December 31, 2004. Although the Frozen DSOP was an option plan rather than a deferred compensation plan, Dominion are including information regarding the plan and any balances in this table to make full disclosure about possible future payments to officers under the 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 2009 as follows: Vanguard 500 Index Fund, 26.5%; Dominion Resources Stock Fund, 13.5%; and Dominion Fixed Income Fund, 5.29%. 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 2009 as noted.
POTENTIAL PAYMENTS UPON TERMINATION OR CHANGE IN CONTROL
Under certain circumstances, the company 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. This section describes and explains these benefits generally, and specifically the incremental benefits that pertain to the NEOs other than Mr. Chewning, who retired on June 1, 2009.
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 officer must either be terminated without cause, or terminate his or her employment with the surviving company after a “constructive termination.” Constructive termination means the officer’s salary, incentive compensation or job responsibility is reduced after a change in control, or the officer’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 officer’s employment following a change in control is terminated without cause or due to a constructive termination, the officer will become entitled to the following termination benefits:

Lump sum severance payment equal to three times base salary plus AIP bonus (determined as the greater of (i) the target annual bonus for the current year or (ii) the highest actual bonus amount paid 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 Plans 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 the company 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 of 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 officer incurs the excise tax, the company will pay the officer 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, assuming the triggering event set forth in the table occurred on December 31, 2009.
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 attaining 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 60. Under the terms of a retention arrangement, 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 will earn a lifetime benefit under the ESRP if he remains employed with the company until he attains age 50. If Mr. Koonce leaves Dominion after he attains age 50 but 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.
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, 2009. 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.
Incremental Payments Upon Termination and Change in Control
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 in the year presented.
(1) Grants made in 2007, 2008 and 2009 under the LTIP vest pro-rata upon termination without cause, death or disability. These grants vest pro-rata upon retirement provided the CEO of Dominion (or in the case of the CEO, the CGN Committee) determines the NEO’s retirement is not detrimental to the company; amounts shown in the table assume this determination was made. The amounts shown in the restricted stock column are based on the closing stock price of $38.92 on December 31, 2009.
(2) Pursuant to a letter agreement dated February 28, 2003, Mr. Farrell will be entitled to a special payment of one times salary in exchange for a two-year non-compete agreement. Mr. Farrell would not be entitled to this non-compete payment in the event of his death.
(3) Amounts in this column represent the value of the incremental benefit that the executives would receive for executive life insurance and retiree medical coverage. Executive life insurance for Mr. McGettrick is only available upon a change in control. Mr. McGettrick is eligible for retiree medical coverage if terminated without cause. Mr. Koonce will not be age 55 even with the added age provided under a change in control and therefore he is not eligible for retiree medical coverage. Messrs. Farrell and Christian are entitled to executive life insurance coverage and retiree medical coverage upon any termination since they are retirement eligible and have completed 10 years of service. Retiree health benefits have been quantified using assumptions used for financial accounting purposes.
(4) The amounts indicated upon a change in control are the incremental amounts that each NEO would receive over the amounts payable upon a retirement (Messrs. Farrell and Christian), voluntary termination or termination without cause (Messrs. McGettrick, Koonce and Heacock).
(5) For Messrs. Farrell and Christian, who are eligible for retirement, the table above assumes they would retire in connection with any termination event, including death or disability.
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 2010 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 2010 Proxy Statement is incorporated by reference.
VIRGINIA POWER
The table below sets forth as of February 19, 2010, 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.
(1) No individual executive officer has the right to acquire beneficial ownership within 60 days of February 19, 2010. Includes shares as to which voting and /or investment power is shared with or controlled by another person as follows: Mr. Rogers, 592 (shares held in joint tenancy).
(2) All directors and executive officers as a group own less than one percent of the number of Dominion common shares outstanding as of February 19, 2010. No individual executive officer or director owns more than one percent of the shares outstanding.
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 2010 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 guidelines were adopted for the purpose of identifying potential conflicts of interest arising out of financial transactions, arrangements and relations between the Company and any related persons. Under Virginia Power’s 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 Dominion (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.
Virginia Power’s guidelines set forth certain transactions that are not considered to be related party transactions including, 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 Corporate Secretary and the General Counsel 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, 2009 there have been no related party transactions involving the Company that were required either to be approved under the Company’s policies or reported under the SEC related party transactions rules.
Director Independence
Under New York Stock Exchange (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 2010 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, 2009 and 2008.
Audit Fees represent fees of Deloitte & Touche 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, audits of Virginia Power’s employee benefit plans, due diligence related to mergers, acquisitions, and investments, and accounting consultations about the application of generally accepted accounting principles to proposed transactions.
Virginia Power’s board has adopted the 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 2009 meeting, the DRI Audit Committee approved Virginia Power’s schedule of services and fees for 2010. 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.
Part IV
Item 15. Exhibits and Financial Statement Schedules
(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 55.
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
3.1.a
Dominion Resources, Inc. Articles of Incorporation as in effect August 9, 1999, as amended effective March 12, 2001 (Exhibit 3.1, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended November 9, 2007 (Exhibit 3, Form 8-K filed November 9, 2007, File No. 1-8489)(filed herewith).
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 February 26, 2010 (filed herewith).
X
3.2.a.1
Dominion Resources, Inc. Amendment to Bylaws, effective February 26, 2010 (filed herewith).
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
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,
X
X
Exhibit
Number
Description
Dominion
Virginia
Power
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).
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
X
Exhibit
Number
Description
Dominion
Virginia
Power
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).
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
Exhibit
Number
Description
Dominion
Virginia
Power
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
10.4
$3.0 billion Five-Year Credit Agreement dated February 28, 2006 among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A. as Syndication Agent and Barclay’s Bank PLC, The Bank of Nova Scotia and Wachovia Bank, National Association, as Co-Documentation Agents and other lenders named therein. (Exhibit 10.1, Form 8-K filed March 3, 2006, File No. 1-8489 and File No. 1-2255).
X
X
10.5
$1.70 billion Amended and Restated Five-Year Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclay’s Bank PLC, as Administrative Agent, Barclays Bank PLC and KeyBank National Association, as Syndication Agents, and SunTrust Bank, The Bank of Nova Scotia and ABN AMRO Bank, N.V., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.2, Form 8-K filed March 3, 2006, File No. 1-8489).
X
10.6
$500 million 364-Day Revolving Credit Agreement dated July 30, 2008 among Dominion Resources, Inc., The Royal Bank of Scotland PLC, as Administrative Agent, Barclays Bank PLC and Morgan Stanley Bank, as Co-Syndication Agents, Citibank N.A. and The Bank of Nova Scotia, as Co-Documentation Agents and other lenders named therein (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).
X
10.7
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
10.8*
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
10.9*
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
10.10*
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
10.11*
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
10.12*
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
Exhibit
Number
Description
Dominion
Virginia
Power
10.13*
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
10.14*
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
10.15*
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
10.16*
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
10.17*
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
10.18*
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 (filed herewith).
X
10.19*
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
10.20*
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated December 16, 2005 (Exhibit 10.2, Form 8-K filed December 16, 2005, File No. 1-8489).
X
10.21*
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
10.22*
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
10.23*
Letter agreement between Dominion Resources, Inc. and Thomas N. Chewning, dated February 28, 2003 (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489).
X
Exhibit
Number
Description
Dominion
Virginia
Power
10.24*
Consulting Agreement between Dominion Resources, Inc. and Thomas N. Chewning, effective September 1, 2009 (Exhibit 10, Form 10-Q for quarter ended September 30, 2009 filed November 2, 2009, 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 April 22, 2005 between Dominion Resources, Inc. and Mark F. McGettrick (Exhibit 10.36, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489).
X
10.27*
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
10.28*
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
10.29*
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
10.30*
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
10.31*
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
10.32*
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
10.33
Offshore Package Purchase Agreement between Dominion Exploration & Production, Inc. and Eni Petroleum dated April 27, 2007 (Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2007 filed May 3, 2007, File No. 1-8489).
X
10.34
Alabama/Permian Package Purchase Agreement dated as of June 1, 2007 between Dominion Resources, Inc., through certain of its wholly owned subsidiaries, and L O & G Acquisition Corp. (Exhibit 10.1, Form 8-K filed June 7, 2007, File No. 1-8489).
X
10.35
Gulf Coast/Rockies/San Juan Package Purchase Agreement dated as of June 1, 2007 between Dominion Resources, Inc. through certain of its wholly owned subsidiaries, and XTO Energy, Inc. (Exhibit 10.2, Form 8-K filed June 7, 2007, File No. 1-8489).
X
10.36*
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
10.37*
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
10.38*
Restricted Stock Award Agreement for Thomas N. Chewning approved March 27, 2008 (Exhibit 10.3, Form 8-K filed April 2, 2008, File No. 1-8489).
X
10.39*
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
10.40*
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
10.41*
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
Exhibit
Number
Description
Dominion
Virginia
Power
10.42*
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).
X
X
10.43*
Restricted Stock Agreement for James F. Stutts approved February 23, 2009 (filed herewith).
X
10.44*
Letter agreement between Dominion Resources, Inc. and James F. Stutts, dated September 22, 1997 (filed herewith).
X
10.45*
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
10.46*
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
10.47*
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).
X
10.48*
Non-employee directors’ annual compensation for Dominion Resources, Inc. (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
Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
Consent of Deloitte & Touche LLP (filed herewith).
X
X
23.1
Consent of Ryder Scott Company, L.P. (filed herewith).
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
Reserve Audit Report of Ryder Scott Company, L.P. as of December 31, 2009 (filed herewith).
X
The following financial statements from Dominion Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 26, 2009, 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, tagged as blocks of text.
X
* Indicates management contract or compensatory plan or arrangement.
Signatures
DOMINION
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.
DOMINION RESOURCES, INC.
By:
/S/ THOMAS F. FARRELL II
(Thomas F. Farrell II, Chairman, President and Chief Executive Officer)
Date: February 26, 2010
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 26th day of February, 2010.
Signature
Title
/S/ THOMAS F. FARRELL II
Thomas F. Farrell II
Chairman of the Board of Directors, President and Chief
Executive Officer
/S/ WILLIAM P. BARR
William P. Barr
Director
/S/ PETER W. BROWN
Peter W. Brown
Director
/S/ GEORGE A. DAVIDSON, JR.
George A. Davidson, Jr.
Director
/S/ JOHN W. HARRIS
John W. Harris
Director
/S/ ROBERT S. JEPSON, JR.
Robert S. Jepson, Jr.
Director
/S/ MARK J. KINGTON
Mark J. Kington
Director
/S/ BENJAMIN J. LAMBERT, III
Benjamin J. Lambert, III
Director
/S/ MARGARET A. MCKENNA
Margaret A. McKenna
Director
/S/ FRANK S. ROYAL
Frank S. Royal
Director
/S/ ROBERT H. SPILMAN, JR.
Robert H. Spilman, Jr.
Director
/S/ DAVID A. WOLLARD
David A. Wollard
Director
/S/ MARK F. MCGETTRICK
Mark F. McGettrick
Executive Vice President and Chief Financial Officer
/S/ ASHWINI SAWHNEY
Ashwini Sawhney
Vice President and Controller (Chief Accounting Officer)
VIRGINIA POWER
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.
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 26, 2010
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 26th day of February, 2010.
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 Index
Exhibit
Number
Description
Dominion
Virginia
Power
3.1.a
Dominion Resources, Inc. Articles of Incorporation as in effect August 9, 1999, as amended effective March 12, 2001 (Exhibit 3.1, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489), as amended November 9, 2007 (Exhibit 3, Form 8-K filed November 9, 2007, File No. 1-8489)(filed herewith).
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 February 26, 2010 (filed herewith).
X
3.2.a.1
Dominion Resources, Inc. Amendment to Bylaws, effective February 26, 2010 (filed herewith).
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
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,
X
X
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).
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 Supplemental
X
Exhibit
Number
Description
Dominion
Virginia
Power
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).
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
10.4
$3.0 billion Five-Year Credit Agreement dated February 28, 2006 among Dominion Resources, Inc., Virginia Electric and Power Company, Consolidated Natural Gas Company, JP Morgan Chase Bank, N.A., as Administrative Agent, Citibank, N.A. as Syndication Agent and Barclay’s Bank PLC, The Bank of Nova Scotia and Wachovia Bank, National Association, as Co-Documentation Agents and other lenders named therein. (Exhibit 10.1, Form 8-K filed March 3, 2006, File No. 1-8489 and File No. 1-2255).
X
X
10.5
$1.70 billion Amended and Restated Five-Year Credit Agreement dated February 28, 2006 among Consolidated Natural Gas Company, Barclay’s Bank PLC, as Administrative Agent, Barclays Bank PLC and KeyBank National Association, as Syndication Agents, and SunTrust Bank, The Bank of Nova Scotia and ABN AMRO Bank, N.V., as Co-Documentation Agents and other lenders as named therein. (Exhibit 10.2, Form 8-K filed March 3, 2006, File No. 1-8489).
X
10.6
$500 million 364-Day Revolving Credit Agreement dated July 30, 2008 among Dominion Resources, Inc., The Royal Bank of Scotland PLC, as Administrative Agent, Barclays Bank PLC and Morgan Stanley Bank, as Co-Syndication Agents, Citibank N.A. and The Bank of Nova Scotia, as Co-Documentation Agents and other lenders named therein (Exhibit 10.1, Form 10-Q for the quarter ended September 30, 2008 filed October 30, 2008, File No. 1-8489).
X
10.7
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
10.8*
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
10.9*
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
10.10*
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
10.11*
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
10.12*
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
Exhibit
Number
Description
Dominion
Virginia
Power
10.13*
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
10.14*
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
10.15*
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
10.16*
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
10.17*
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
10.18*
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 (filed herewith).
X
10.19*
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
10.20*
Dominion Resources, Inc. Executive Stock Purchase Tool Kit, effective September 1, 2001, amended and restated December 16, 2005 (Exhibit 10.2, Form 8-K filed December 16, 2005, File No. 1-8489).
X
10.21*
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
10.22*
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
10.23*
Letter agreement between Dominion Resources, Inc. and Thomas N. Chewning, dated February 28, 2003 (Exhibit 10.25, Form 10-K for the fiscal year ended December 31, 2002 filed March 20, 2003, File No. 1-8489).
X
Exhibit
Number
Description
Dominion
Virginia
Power
10.24*
Consulting Agreement between Dominion Resources, Inc. and Thomas N. Chewning, effective September 1, 2009 (Exhibit 10, Form 10-Q for quarter ended September 30, 2009 filed November 2, 2009, 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 April 22, 2005 between Dominion Resources, Inc. and Mark F. McGettrick (Exhibit 10.36, Form 10-K for the fiscal year ended December 31, 2005 filed March 2, 2006, File No. 1-8489).
X
10.27*
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
10.28*
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
10.29*
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
10.30*
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
10.31*
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
10.32*
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
10.33
Offshore Package Purchase Agreement between Dominion Exploration & Production, Inc. and Eni Petroleum dated April 27, 2007 (Exhibit 10.5 to Form 10-Q for the quarter ended March 31, 2007 filed May 3, 2007, File No. 1-8489).
X
10.34
Alabama/Permian Package Purchase Agreement dated as of June 1, 2007 between Dominion Resources, Inc., through certain of its wholly owned subsidiaries, and L O & G Acquisition Corp. (Exhibit 10.1, Form 8-K filed June 7, 2007, File No. 1-8489).
X
10.35
Gulf Coast/Rockies/San Juan Package Purchase Agreement dated as of June 1, 2007 between Dominion Resources, Inc. through certain of its wholly owned subsidiaries, and XTO Energy, Inc. (Exhibit 10.2, Form 8-K filed June 7, 2007, File No. 1-8489).
X
10.36*
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
10.37*
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
10.38*
Restricted Stock Award Agreement for Thomas N. Chewning approved March 27, 2008 (Exhibit 10.3, Form 8-K filed April 2, 2008, File No. 1-8489).
X
10.39*
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
10.40*
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
10.41*
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
Exhibit
Number
Description
Dominion
Virginia
Power
10.42*
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).
X
X
10.43*
Restricted Stock Agreement for James F. Stutts approved February 23, 2009 (filed herewith).
X
10.44*
Letter agreement between Dominion Resources, Inc. and James F. Stutts, dated September 22, 1997 (filed herewith).
X
10.45*
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
10.46*
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
10.47*
Base salaries for named executive officers of Dominion Resources, Inc. (filed herewith).
X
10.48*
Non-employee directors’ annual compensation for Dominion Resources, Inc. (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
Subsidiaries of Dominion Resources, Inc. and Virginia Electric and Power Company (filed herewith).
X
X
Consent of Deloitte & Touche LLP (filed herewith).
X
X
23.1
Consent of Ryder Scott Company, L.P. (filed herewith).
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
Reserve Audit Report of Ryder Scott Company, L.P. as of December 31, 2009 (filed herewith).
X
The following financial statements from Dominion Resources, Inc. Annual Report on Form 10-K for the year ended December 31, 2009, filed on February 26, 2009, 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, tagged as blocks of text.
X
* Indicates management contract or compensatory plan or arrangement.