THE COMPANY

Dominion Resources, Inc. (Dominion) is a fully integrated gas and electric holding company headquartered in Richmond, Virginia. Dominion was incorporated in Virginia in 1983.

Dominion concentrates its efforts largely in the energy intensive Northeast, Mid-Atlantic and Midwest regions of the United States (U.S.).

The terms “Dominion,” “Company,” “we,” “our” and “us” are used throughout this report and, depending on the context of their use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

Our principal direct legal subsidiaries are Virginia Electric and Power Company (Virginia Power), Consolidated Natural Gas Company (CNG), Dominion Energy, Inc. (DEI) and Virginia Power Energy Marketing, Inc. (VPEM). Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. CNG operates in all phases of the natural gas business, explores for and produces natural gas and oil and provides a variety of energy marketing services. In addition, CNG is a transporter, distributor and retail marketer of natural gas, serving customers in Pennsylvania, Ohio, West Virginia and other states. CNG also operates a liquefied natural gas (LNG) import and storage facility in Maryland. DEI is involved in merchant generation, energy marketing and price risk management activities and natural gas and oil exploration and production. VPEM provides fuel and price risk management services to Virginia Power and other Dominion affiliates and engages in energy trading activities.

As of December 31, 2006, we had approximately 17,500 full-time employees. Approximately 6,300 employees are subject to collective bargaining agreements.

Our principal executive offices are located at 120 Tredegar Street, Richmond, Virginia 23219 and our telephone number is (804) 819-2000.

WHERE YOU CAN FIND MORE INFORMATION ABOUT DOMINION

We file our annual, quarterly and current reports, proxy statements and other information with the Securities and Exchange Commission (SEC). Our SEC filings are available to the public over the Internet at the SEC’s website at http://www.sec.gov (File No. 001-08489). You may also read and copy any document we 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.

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

SIGNIFICANT DEVELOPMENTS

Following are significant acquisitions and divestitures during the last five years.

Acquisitions

PABLO ENERGY, LLC

In February 2006, we completed the acquisition of Pablo Energy, LLC (Pablo) for approximately $92 million in cash. Pablo holds producing and other properties located in the Texas Panhandle area. The operations of Pablo are included in our Dominion Exploration and Production (E&P) operating segment.

KEWAUNEE POWER STATION

In July 2005, we completed the acquisition of the 556-megawatt (Mw) Kewaunee nuclear power station (Kewaunee), located in northeastern Wisconsin, from Wisconsin Public Services Corporation for approximately $192 million in cash. The operations of Kewaunee are included in our Dominion Generation operating segment.

USGEN POWER PLANTS

In January 2005, we completed the acquisition of three fossil-fired generation facilities from USGen New England, Inc. for $642 million in cash. The plants include the 1,560 Mw Brayton Point Power Station in Somerset, Massachusetts; the 754 Mw Salem Harbor Station in Salem Massachusetts; and the 432 Mw Manchester Street Station in Providence, Rhode Island. The operations of these facilities are included in our Dominion Generation operating segment.

COVE POINT LNG LIMITED PARTNERSHIP

In September 2002, we acquired 100% ownership of Cove Point LNG Limited Partnership (Cove Point), a cost based rate-regulated entity from a subsidiary of The Williams Companies for $225 million in cash. Cove Point’s assets include an LNG natural gas import and storage facility located near Baltimore, Maryland and an approximately 85-mile natural gas pipeline. Cove Point is included in our Dominion Energy operating segment.

MIRANT STATE LINE VENTURES, INC.

In June 2002, we acquired 100% ownership of Mirant State Line Ventures (State Line) from a subsidiary of Mirant Corporation for $185 million in cash. State Line’s assets include a 515 Mw generation facility located near Hammond, Indiana. Its operations are included in our Dominion Generation operating segment.

Dispositions

SALE OF E&P PROPERTIES

In 2006, we received approximately $393 million of proceeds from sales of certain gas and oil properties, primarily resulting from the fourth quarter sale of certain properties located in Texas and New Mexico. In December 2004, we sold the majority of our natural gas and oil assets in British Columbia, Canada for $476 million. These assets were included in our Dominion E&P operating segment.

PENDING SALES

In addition to the completed acquisitions and divestitures above, we have entered into an agreement with Equitable Resources, Inc. to sell two of our wholly-owned regulated gas distribution subsidiaries for approximately $970 million plus adjustments to

reflect capital expenditures and changes in working capital. We have also entered into an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell three of our natural gas-fired merchant generation peaking facilities for approximately $256 million. A more detailed description of these activities can be found in our discussion of our Dominion Delivery and Dominion Generation operating segments.

POTENTIAL SALE OF SUBSTANTIAL PORTION OF E&P ASSETS

In November 2006, we announced our decision to pursue the sale of all of our oil and natural gas E&P operations and assets, with the exception of those located in the Appalachian Basin. As of December 31, 2006, our natural gas and oil assets—excluding the Appalachian Basin—included about 5.5 trillion cubic feet of proved reserves. The Appalachian assets that we would retain constituted approximately 15% of our total reserves as of December 31, 2006. These operations and assets are principally part of our Dominion E&P operating segment. See Introduction in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

OPERATING SEGMENTS

We manage our operations through four primary operating segments: Dominion Delivery, Dominion Energy, Dominion Generation and Dominion E&P. We also report a Corporate segment that includes our corporate, service company and other functions. While we manage our daily operations through our operating segments, our assets remain wholly-owned by our legal subsidiaries. For additional financial information on business segments and geographic areas, including revenues from external customers, see Note 28 to our Consolidated Financial Statements. For additional information on operating revenue related to our principal products and services, see Note 6 to our Consolidated Financial Statements.

Dominion Delivery

Dominion Delivery includes our regulated electric and gas distribution and customer service businesses, as well as nonregulated retail energy marketing operations. Electric distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina. Gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Nonregulated retail energy marketing operations include the marketing of gas, electricity and related products and services to residential, industrial and small commercial customers in the Northeast, Mid-Atlantic and Midwest.

In March 2006, we entered into an agreement with Equitable Resources, Inc. to sell two of our wholly-owned regulated gas distribution subsidiaries, The Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), for approximately $970 million plus adjustments to reflect capital expenditures and changes in working capital. Peoples and Hope serve approximately 500,000 customer accounts in Pennsylvania and West Virginia. The transaction is expected to close by the end of the second quarter of 2007, subject to state regulatory approvals in Pennsylvania and West Virginia, as well as approval under the Hart-Scott-Rodino Act.

COMPETITION

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

Retail competition for gas supply exists to varying degrees in the three states in which our gas distribution subsidiaries operate. In Pennsylvania, supplier choice is available for all residential and small commercial customers. In Ohio, there has been no legislation enacted to require supplier choice for residential and commercial natural gas consumers. However, we have offered an Energy Choice program to customers, in cooperation with the Public Utilities Commission of Ohio (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 Delivery’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission). See Regulation—State Regulations—Electric for additional information.

Dominion Delivery’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio Commission, the Pennsylvania Public Utility Commission (Pennsylvania Commission) and the West Virginia Public Service Commission (West Virginia Commission). See Regulation—State Regulations—Gas for additional information.

PROPERTIES

Dominion Delivery’s electric distribution network includes approximately 55,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The rights-of-way grants for most electric lines have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly owned property, where permission to operate can be revoked.

Dominion Delivery’s gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. This network involves approximately 27,700 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. Delivery also operates 10 underground gas storage fields located in Ohio and Pennsylvania, with more than 800 storage wells and approximately 121,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Delivery is approximately 203 billion cubic feet (bcf). The Dominion Delivery segment has about 40 compressor stations with approximately 65,000 horsepower of installed compression.

SOURCES OF ENERGY SUPPLY

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

Dominion Delivery is engaged in the sale and storage of natural gas through its operating subsidiaries. Dominion Delivery’s natural gas supply is obtained from various sources including

purchases from: major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area, and gas marketers.

SEASONALITY

Dominion Delivery’s business varies seasonally as a result of the impact of changes in temperature on demand by residential and commercial customers for electricity, to meet cooling and heating needs, and gas, to meet heating needs.

Dominion Energy

Dominion Energy includes our regulated electric transmission, natural gas transmission pipeline and storage businesses and the Cove Point LNG facility. It also includes gathering and extraction activities, plus certain Appalachian natural gas production. Dominion Energy also includes producer services, which consist of aggregation of gas supply, market-based services related to gas transportation and storage, associated gas trading and the results of certain energy trading activities exited in December 2004. The electric transmission business serves Virginia and northeastern North Carolina. In 2005, we became a member of PJM Interconnection, LLC (PJM), a regional transmission organization (RTO), and integrated our electric transmission facilities into the PJM wholesale electricity markets. The gas transmission pipeline and storage business serves our gas distribution businesses and other customers in the Northeast, Mid-Atlantic and Midwest.

COMPETITION

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

Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. We also compete 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 our own pipeline system enables us to tailor our services to meet the needs of individual customers.

REGULATION

Dominion Energy’s electric transmission rates, tariffs and terms of service are subject to regulation by the Federal Energy Regulatory Commission (FERC). FERC also regulates our natural gas pipeline transmission, storage and LNG operations. Electric trans

mission siting authority remains the exclusive jurisdiction of the Virginia and North Carolina Commissions. However, the Energy Policy Act of 2005 provides FERC with certain limited backstop authority for transmission siting, the implications of which remain unclear. See State Regulations and Federal Regulations in Regulation for additional information.

PROPERTIES

Dominion Energy has approximately 6,000 miles of electric transmission lines of 69 kilovolt (kV) or more located in the states of North Carolina, Virginia and West Virginia. Portions of Dominion Energy’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 we continue to own and maintain these electric transmission facilities, they are now a part of PJM, which coordinates the planning, operation, emergency assistance and exchange of capacity and energy for such facilities.

Each year, as part of PJM’s Regional Transmission Expansion Plan (RTEP) process, reliability projects are authorized. In June 2006, PJM, through the RTEP process, authorized construction of numerous electric transmission upgrades through 2011. We are involved in two of the major construction projects. The first project is an approximately 270-mile 500 kV transmission line from southwestern Pennsylvania to Virginia, of which we will construct approximately 70 miles in Virginia and a subsidiary of Allegheny Energy, Inc. will construct the remainder. The second project is an approximately 56-mile 500 kV transmission line that we will construct in southeastern Virginia. These transmission upgrades are designed to improve the reliability of service to our customers and the region. The siting and construction of these transmission lines will be subject to applicable state and federal permits and approvals.

Dominion Energy has approximately 7,800 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 17 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with more than approximately 1,500 storage wells and approximately 252,000 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 776 bcf. Six storage fields are jointly-owned and operated by Dominion Energy. The capacity of those six fields owned by our partners totals about 242 bcf. Dominion Energy also has about 8 bcf of above-ground storage capacity at its Cove Point LNG facility. Dominion Energy has about 90 compressor stations with approximately 630,000 installed compressor horsepower.

SOURCES OF ENERGY SUPPLY

Our large underground natural gas storage network and the location of our pipeline system are a significant link between the country’s major interstate gas pipelines and large markets in the Northeast and Mid-Atlantic regions. Our 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.

Our 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 transport capacity.

SEASONALITY

Dominion Energy’s nonregulated businesses are affected by seasonal changes in the prices of commodities that they transport, store and actively market and trade.

Dominion Generation

Dominion Generation’s electric utility and merchant fleet includes approximately 28,000 Mw of generation capability. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. Our electric generation operations serve customers in the Northeast, Mid-Atlantic and Midwest.

Our generation facilities are located in Virginia, West Virginia, North Carolina, Connecticut, Illinois, Indiana, Pennsylvania, Ohio, Massachusetts, Rhode Island and Wisconsin. Dominion Generation also includes energy marketing and price risk management activities for our generation assets.

In December 2006, we reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell three of our natural gas-fired merchant generation peaking facilities (Peaker facilities). Peaking facilities are used during times of high electricity demand, generally in the summer months. The Peaker facilities are:

The sale is expected to result in proceeds of approximately $256 million and is expected to close by the end of the first quarter of 2007, pending regulatory approval by FERC. We have obtained approval from the Federal Trade Commission. No state regulatory approvals are required.

We offered the facilities for sale following a review of our portfolio of assets. We have decided not to sell a fourth merchant generation facility, State Line, a 515 Mw coal-fired facility in Hammond, Indiana.

COMPETITION

Retail choice has been available for Dominion Generation’s Virginia jurisdictional electric utility customers since January 1, 2003; however, to date, competition in Virginia has not developed to any significant extent. See Regulation—State Regulations. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation’s merchant generation fleet owns and operates several large facilities in the Midwest. The output from these generating plants is sold under long-term contracts and is therefore largely unaffected by competition.

Dominion Generation’s remaining merchant assets operate within functioning RTOs. 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 operating reserves. 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, we apply our expertise in operations, dispatch and risk management to maximize the degree to which our merchant fleet is competitive compared to similar assets within the region.

REGULATION

The operations of Dominion Generation are subject to regulation by FERC, the Nuclear Regulatory Commission (NRC), the Environmental Protection Agency (EPA), the Department of Energy (DOE), the Army Corps of Engineers, the Virginia Commission, the North Carolina Commission and other federal, state and local authorities. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

For a listing of Dominion Generation’s current generation facilities, see Item 2. Properties.

In December 2006, we acquired a 50% interest in a joint venture with Shell WindEnergy Inc. (Shell) to develop a wind-turbine facility in Grant County, West Virginia, which will produce approximately 164 Mw of electricity and is expected to begin operations in the fourth quarter of 2007.

Based on available generation capacity and current estimates of growth in customer demand, we will need additional generation in the future. We currently have plans to restart our Hopewell plant in 2007, a 63 Mw (at net summer capability) coal burning plant located in Hopewell, Virginia which has been out of service since 2002, and we are evaluating a 290 Mw (at net summer capability) expansion of our Ladysmith site in Ladysmith, Virginia. We are also leading a consortium of companies that are considering building a 500 to 600 Mw coal-fired plant in southwest Virginia. We will continue to evaluate the development of new plants to meet customer demand for additional generation needs in the future.

SOURCES OF ENERGY SUPPLY

Dominion Generation uses a variety of fuels to power our electric generation, as described below.

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.

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 our gas turbine fleet, while minimizing costs.

SEASONALITY

Dominion Generation’s sales of electricity typically vary seasonally based on demand for electricity by residential and commercial customers for cooling and heating use based on changes in temperature. Sales of electricity from our merchant generation plants are also affected by seasonal changes in demand and commodity prices.

NUCLEAR DECOMMISSIONING

Dominion Generation has a total of seven licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia, its Millstone plant in Connecticut and its Kewaunee plant in Wisconsin.

Surry and North Anna serve customers of our regulated electric utility operations. Millstone and Kewaunee are nonregulated merchant plants. Millstone has two operating units. A third Millstone unit ceased operations before we acquired the plant.

Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power plant 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. As part of our acquisition of both Millstone and Kewaunee, we acquired decommissioning funds for the related units. We believe that the amounts currently available in our decommissioning trusts and their expected earnings will be sufficient to cover expected decommissioning costs for the Millstone and Kewaunee units, without any additional contributions to those trusts.

The total estimated cost to decommission our eight nuclear units is $4.1 billion in 2006 dollars and is primarily based upon site-specific studies completed in 2006. For all units except Millstone Unit 1 and Unit 2, the current cost estimates assume 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 units. We expect 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 2059. We expect to decommission the Surry and North Anna units during the period 2032 to 2059. We intend to apply for a 20-year life extension in 2008 for our Kewaunee unit. If the NRC approves the life extension application, we expect to decommission Kewaunee during the period 2033 to 2059. The license expiration dates for our units are shown in the following table.

Dominion E&P

Dominion E&P includes our gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico, West Texas, Mid-Continent, the Rockies and Appalachia, as well as the Western Canadian Sedimentary Basin.

In November 2006, we announced our decision to pursue the sale of all of our oil and natural gas E&P operations and assets, with the exception of those located in the Appalachian Basin. Any disposition would allow us to focus on our electric generating and energy distribution, transmission and storage businesses and realign our operations and risk profile more closely with our peer investment group of utilities. As of December 31, 2006, our natural gas and oil assets—excluding the Appalachian Basin—included about 5.5 trillion cubic feet of proved reserves. The Appalachian assets that we would retain constitute approximately 15% of our total proved reserves.

Proceeds from any sale are expected to be used to reduce debt repurchase shares of our common stock, and/or acquire assets related to our remaining core businesses. We expect to initiate a formal sales process in early 2007. Closing of any sale or sales is targeted for mid-2007.

In February 2006, we completed the acquisition of Pablo for approximately $92 million in cash. Pablo holds producing and other properties located in the Texas Panhandle area. In 2006, we received approximately $393 million of proceeds from the sale of gas and oil properties, primarily resulting from the fourth quarter sale of certain properties located in Texas and New Mexico.

COMPETITION

Dominion E&P’s competitors range from major, international oil companies to smaller, independent producers. Dominion E&P faces significant competition in bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. As the operator of production properties, Dominion E&P also faces competition in securing drilling equipment and supplies for exploration and development.

Dominion E&P sells most of its deliverable natural gas and oil into short and intermediate-term markets. Dominion E&P faces challenges related to the marketing of its natural gas and oil pro-

duction due to the contraction of participants in the energy marketing industry. However, Dominion E&P owns a large and diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions, which strengthens its knowledge of the marketplace and delivery options.

REGULATION

Our E&P operations are subject to regulation by numerous federal and state authorities. The pipeline transportation of our natural gas production is regulated by FERC; pipelines operating on or across the Outer Continental Shelf are subject to the Outer Continental Shelf Lands Act, which requires services to be offered on an open-access, non-discriminatory basis. Our production operations in the Gulf of Mexico and most of our operations in the western U.S. are located on property subject to federal oil and gas leases that are administered by the Minerals Management Service (MMS) or the Bureau of Land Management. These leases are issued through a competitive bidding process and require us to comply with stringent regulations. Offshore production facilities must comply with MMS regulations relating to engineering, construction, operations and the plugging and abandonment of wells. Our production operations are also subject to environmental regulations including regulations relating to oil spills into navigable waters of the U.S. See Regulation—Federal Regulations and Regulation—Environmental Regulations for additional information.

PROPERTIES

Dominion E&P owns 6.5 trillion cubic feet proved equivalent of natural gas and oil reserves and produces approximately 1.3 billion cubic feet equivalent of natural gas per day from its leasehold acreage and facility investments. Either alone or with partners, we hold interests in natural gas and oil lease acreage, wellbores, well facilities, production platforms and gathering systems. We also own or hold rights to seismic data and other tools used in exploration and development drilling activities. Our share of developed leasehold totals 3.2 million acres, with another 2.0 million acres held for future exploration and development drilling opportunities. See also Item 2. Properties for additional information on Dominion E&P’s properties.

SEASONALITY

Dominion E&P’s business can be affected by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for our unhedged natural gas and oil production, can be affected by seasonal weather changes and by the effects of weather on operations.

Corporate

We also have a Corporate segment that includes:

REGULATION

We are subject to regulation by the Virginia Commission, the North Carolina Commission, the Securities and Exchange

Commission (SEC), FERC, the EPA, the DOE, the NRC, the Army Corps of Engineers and other federal, state and local authorities.

State Regulations

ELECTRIC

Our electric retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.

Our electric utility subsidiary 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, this subsidiary 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 North Carolina Commission regulate our electric utility subsidiary’s transactions with affiliates, transfers of certain facilities and issuance of securities.

Rates

Historically, the rates of our electric utility subsidiary have been based on the cost of providing traditional bundled electric service (i.e., the combination of generation, transmission and distribution services). As a result of the Virginia Electric Utility Restructuring Act enacted in 1999 (1999 Virginia Restructuring Act), in Virginia, rates have been transitioning to unbundled

cost-based rates for transmission and distribution services, and to market pricing for generation services, including retail choice for our customers. In North Carolina, rates are still based on the cost of providing traditional bundled electric service; however the base rates of our electric utility are currently subject to a rate moratorium, as described below.

The following is a discussion of our current rate structure; however, such structure is subject to change under proposed new restructuring legislation described under Status of Electric Restructuring in Virginia.

Virginia—We provide retail electric service in Virginia at unbundled rates. In Virginia, our base rates are capped at 1999 levels until the sooner of (1) the end of a transition period (now December 31, 2010) or (2) a Virginia Commission order finding that a competitive market for generation exists in the Commonwealth. In 2004, the Virginia fuel factor statute was amended to lock in our fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates, with no adjustment for previously incurred over-recovery or under-recovery of fuel costs, thus eliminating deferred fuel accounting for the Virginia jurisdiction. However, in May 2006, Virginia law was amended to modify the way our Virginia jurisdictional fuel factor is set during the three and one-half year period beginning July 1, 2007. The bill became law effective July 1, 2006 and:

Fuel prices have increased considerably since our Virginia fuel factor provisions were frozen in 2004, which has resulted in our fuel expenses being significantly in excess of our rate recovery. We expect that fuel expenses will continue to exceed rate recovery until our fuel factor is adjusted in July 2007. While the 2006 amendments do not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor is adjusted, the risk of under-recovery of prudently incurred fuel costs until July 1, 2010 is greatly diminished.

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

Status of Electric Restructuring in Virginia

1999 Virginia Restructuring Act

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

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

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

2007 Virginia Restructuring Act Amendments

In February 2007, both houses of the Virginia General Assembly passed identical bills that would significantly change electricity restructuring in Virginia. The bills would end capped rates two years early, on December 31, 2008. After capped rates end, retail choice would be eliminated for all but individual retail customers with a demand of more than 5 Mw and a limited number of non-residential retail customers whose aggregated load would exceed 5 Mw. Also, after the end of capped rates, the Virginia Commission would set the base rates of investor-owned electric utilities under a modified cost-of-service model. Among other features, the currently proposed model would provide for the Virginia Commission to:

The bills would also continue statutory provisions directing us to file annual fuel cost recovery cases with the Virginia Commission beginning in 2007 and continuing thereafter. However, our fuel factor increase as of July 1, 2007 would be limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of that date, and the remainder would be deferred and collected over three years, as follows:

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

Retail Access Pilot Programs

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

GAS

Our 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 we have 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 and commercial natural gas consumers. However, in cooperation with the Ohio Commission, we have offered retail choice to residential and commercial customers. At December 31, 2006, approximately 814,000 of our 1.2 million Ohio customers were participating in this Energy Choice program. Large industrial customers in Ohio also source their own natural gas supplies. In May 2006, the Ohio Commission approved a two-year pilot program to improve and expand our Energy Choice Program. Under the previous structure, non-Energy Choice customers purchased gas directly from us at a monthly gas cost recovery rate that included true-up adjustments that could change significantly from one quarter to the next. In August 2006, the Ohio Commission approved an auction that enabled us to enter into gas purchase contracts with selected suppliers at a fixed price above the New York Mercantile Exchange month-end settlement. This pricing mechanism, implemented in October 2006, replaces the traditional gas cost recovery rate with a monthly market price that eliminates the true-up adjustment, making it easier for customers to compare and switch to competitive suppliers by the end of the transition period. Subject to Ohio Commission approval, we plan to exit the gas merchant function in Ohio entirely and have all customers select an alternate gas supplier. We will continue to be the provider of last resort in the event of default by a supplier.

Pennsylvania—In Pennsylvania, supplier choice is available for all residential and small commercial customers. At December 31, 2006, approximately 99,000 residential and small commercial customers had opted for Energy Choice in our 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 its retail natural gas markets. 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

Our gas distribution subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Pennsylvania, Ohio and West Virginia. When necessary, our gas distribution subsidiaries seek general base rate increases on a timely basis to recover increased operating costs. In addition to general rate increases, our gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. 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.

Federal Regulations

PUBLIC UTILITY HOLDING COMPANY ACT OF 2005 (PUHCA 2005)

The Energy Policy Act of 2005 (EPACT) provided for the repeal of the Public Utility Holding Company Act of 1935 (1935 Act)

in February 2006. The 1935 Act and related regulations issued by the SEC governed our activities with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in businesses activities not directly related to the utility or energy business and other matters. Since the effective date of repeal of the 1935 Act, we are considered a holding company under PUHCA 2005, the rules and regulations of which are administered by FERC. PUHCA 2005 is more limited in scope than the 1935 Act and relates primarily to certain record-keeping requirements and transactions involving public utilities and their affiliates.

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Our electric utility subsidiary and merchant generators sell electricity in the wholesale market under our market-based sales tariffs authorized by FERC. In addition, our electric utility subsidiary has FERC approval of a tariff to sell wholesale power at capped rates based on our embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside our service territory. Any such sales would be voluntary. Various proceedings that may have a significant effect on electric transmission service rates within the PJM region are ongoing at FERC. The outcome of these cases cannot be determined with any certainty at this point in time.

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

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

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

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 our interstate natural gas company subsidiaries, including Dominion Transmission, Inc. (DTI), Dominion Cove Point LNG, LP (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.

Our interstate gas transportation and storage activities are conducted on an “open access” basis, in accordance with certificates, tariffs and service agreements on file with FERC.

We are 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. We have evaluated our natural gas transmission and storage properties, as required by the Department of Transportation regulations under the 2002 Act, and have implemented a program of identification, testing and potential remediation activities. These activities are ongoing.

In May 2005, FERC approved a comprehensive rate settlement with our subsidiary, DTI, and its customers and interested state commissions. The settlement, which became effective July 1, 2005, revised our natural gas transportation 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 until 2010.

In June 2006, we filed a general rate proceeding for DCP. The rates to be established in this case will take effect as of January 1, 2007. This rate proceeding will enable DCP to update the cost of service underlying its rates, including recovery of costs associated with the 2002 to 2003 reactivation of the LNG import terminal. Resolution of the case is expected during the first half of 2007.

We implemented various other rate filings, tariff changes and negotiated rate service agreements for our FERC-regulated businesses during 2006. In all material respects, these filings were approved by FERC in the form requested by us and were subject to only minor modifications.

FEDERAL OFFSHORE OIL AND GAS LEASE LEGISLATION

A bill passed by the U.S. House of Representatives on January 16, 2007, but not yet enacted into law, addresses certain federal offshore and gas leases issued in 1998 and 1999 that do not include a provision requiring royalties to be paid on specified royalty suspension volumes when oil and gas commodity futures closing prices exceed specified threshold levels (as is the case under current market conditions). The bill imposes certain conservation of resources fees and imposes sanctions on lessees, including disqualification from future offshore lease sales, for those who fail to comply. The Senate is considering such legislation. For further discussion, see Offshore Oil and Gas Leases in Future Issues of MD&A.

Environmental Regulations

Each of our operating segments faces substantial regulation and compliance costs with respect to environmental matters. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, 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 our Consolidated Financial Statements.

The Clean Air Act (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 our facilities are subject to the CAA’s permitting and other requirements. For example, the EPA has established the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). These rules, when

implemented, will require significant reductions in sulfur dioxide (SO₂), nitrogen oxide (NO_X) and mercury emissions from electric generating facilities. States are currently developing implementation plans, which will determine the levels and timing of required emission reductions in each of the states within which we own and operate affected generating facilities. Separate from CAIR and CAMR, Massachusetts has regulations specifically targeting reductions in NO_x, SO₂, carbon dioxide (CO₂) and mercury emissions from our affected facilities in Massachusetts.

In 1997, the U.S. signed an International Protocol (Protocol) to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% over the period 2002 through 2012. Several legislative proposals in the U.S. Congress have in the past and are likely in the future to include provisions seeking to target the reductions of greenhouse gas emissions. In addition to possible federal action, some states in which we operate have already or may adopt carbon reduction programs. For example, Massachusetts has implemented regulations requiring reductions in CO₂ emissions.

The Clean Water Act (CWA) is a comprehensive program requiring a broad range of regulatory tools including a permit program to authorize and regulate discharges to surface waters with strong enforcement mechanisms. We must comply with all aspects of the CWA programs at our operating facilities. Provisions also include requirements that the location, design, construction, and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impact. Additional programs under the CWA address the impact of thermal discharges to surface waters.

From time to time we may be identified as a potentially responsible party (PRP) to a Superfund site. Refer to Note 23 to our Consolidated Financial Statements for a description of our exposure relating to identification as a PRP. We do not believe that any currently identified sites will result in significant liabilities.

We have applied for or obtained the necessary environmental permits for the operation of our facilities. Many of these permits are subject to re-issuance and continuing review.

Nuclear Regulatory Commission

All aspects of the operation and maintenance of our nuclear power stations, which are part of our 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, that action could result in substantial increases in the cost of operating and maintaining our nuclear generating units.

The NRC also requires us to decontaminate our nuclear facilities once operations cease. This process is referred to as decommissioning, and we are required by the NRC to be financially prepared. For information on our decommissioning trusts, see Dominion Generation—Nuclear Decommissioning and Note 23 to our Consolidated Financial Statements.

ITEM 1A. RISK FACTORS

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

Our operations are weather sensitive. Our results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. In addition, severe weather, including hurricanes, winter storms and droughts, can be destructive, causing outages, production delays and property damage that require us to incur additional expenses.

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

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

We are exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia for our regulated electric utility. Under the 1999 Virginia Restructuring Act, as amended, our base rates remain capped through December 31, 2010 unless sooner modified or terminated. Although this Act allows for the recovery of certain generation-related costs during the capped rates period, we remain exposed to numerous risks of cost-recovery shortfalls. These risks include exposure to stranded costs, future environmental compliance requirements, certain tax law changes, costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs.

In addition, our current Virginia fuel factor provisions are locked-in until July 1, 2007, with no deferred fuel accounting. As a result, until July 1, 2007 we are exposed to fuel price and other risks. These risks include exposure to increased costs of fuel, including purchased power costs, differences between our projected and actual power generation mix and generating unit performance (which affects the types and amounts of fuel we use) and differences between fuel price assumptions and actual fuel prices.

Annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, will be instituted for three twelve-month periods beginning July 1, 2007. The Virginia Commission is authorized to defer up to 40% of any fuel factor increase approved for the first twelve-month period, with recovery of the deferred amount over the two and one-half year period beginning July 1, 2008. There will also be an adjustment for one six-month period beginning July 1, 2010. Beginning July 1, 2007, our risk of under-recovering prudently incurred expenses until July 1, 2010 is greatly diminished. Because there will be no adjustment to account for differences between projections and actual recovery of fuel costs at the end of the six-month period beginning July 1, 2010, we will be exposed to fuel price and other risks during that period. Further, after December 31, 2010 (or upon the earlier termination of capped rates), fuel cost recovery provisions will cease and we will be exposed to the fuel price and other related risks as described above.

The foregoing risks are subject to change upon the adoption, if any, of the proposed 2007 legislative amendments. The proposed legislation would end capped rates on December 31, 2008. The proposed legislation also calls for annual fuel cost recovery proceedings, beginning July 1, 2007 and continuing thereafter. The first annual increase as of July 1, 2007 would be limited to an amount that results in residential customers not receiving an increase of more than 4% of total rates as of that date, and the remainder would be deferred and collected in the years 2008 through 2010, as described under Status of Electric Restructuring in Virginia in MD&A. The Governor of Virginia has until March 26, 2007 to sign, propose amendments to, or veto the proposed legislation. We cannot predict the outcome of the legislation at this time.

Our merchant power business is operating in a challenging market, which could adversely affect our results of operations and future growth. The success of our merchant power business depends upon favorable market conditions as well as our ability to find buyers willing to enter into power purchase agreements at prices sufficient to cover operating costs. We attempt to manage these risks by entering into both short-term and long-term fixed price sales and purchase contracts and locating our assets in active wholesale energy markets. However, high fuel and commodity costs and excess capacity in the industry could adversely impact our results of operations.

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

The use of derivative instruments could result in financial losses and liquidity constraints. We use derivative instruments, including futures, forwards, financial transmission rights, options and swaps, to manage our commodity and financial market risks. In addition, we purchase and sell commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. We could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a 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, we use derivatives to hedge future sales of our merchant generation and gas and oil production, which may limit the benefit we would otherwise receive from increases in commodity prices. These hedge arrangements generally include collateral requirements that require us 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. When commodity prices rise to levels substantially higher than the levels where we have hedged future sales, we may be required to use a material portion of our available liquidity and obtain additional liquidity to cover these collateral requirements. In some circumstances, this could have a compounding effect on our 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 our results of operations.

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

For additional information concerning derivatives and commodity-based 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 our Consolidated Financial Statements.

Our 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 our assets. Factors that may affect our financial results include, but are not limited to: damage to or suspension of operations caused by weather, fire, explosion or other events at our or third-party gas and oil facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities, our ability to acquire additional land positions in competitive lease areas, operational risks that could disrupt production and geological and other uncertainties inherent in the estimate of gas and oil reserves.

Short-term market declines in the prices of natural gas and oil could adversely affect our financial results by causing a permanent write-down of our 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 based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

In the past, we have maintained business interruption, property damage and other insurance for our E&P operations. However, the increased level of hurricane activity in the Gulf of Mexico led our insurers to terminate certain coverages for our E&P operations; specifically, our Operator’s Extra Expense (OEE), offshore property damage and offshore business interruption coverage was terminated. All onshore property coverage (with the exception of OEE) and liability coverage commensurate

with past coverage remained in place for our E&P operations. Our OEE coverage for both onshore and offshore E&P operations was reinstated under a new policy. However, efforts to replace the terminated insurance for our E&P operations for offshore property damage and offshore business interruption with similar insurance on commercially reasonable terms were unsuccessful. This lack of insurance could adversely affect our results of operations.

Our decision to pursue a sale of most of our E&P assets is expected to be dilutive to earnings, could have an adverse impact on our results of operations and may not yield the benefits that we expect. On November 1, 2006, we announced our decision to pursue a sale of all of our E&P assets, excluding those assets located in the Appalachian Basin. We expect that a sale of our E&P assets would reduce future earnings in the near term. Although we expect that shareholder value would increase over time, we can give no assurance that this will occur. While our management believes it would be able to execute any sale or sales by mid-2007, we may not be able to sell our E&P assets within the expected time frame. If we sell our E&P assets, we cannot be certain of the price we would receive or the impact that such a sale and the use of proceeds from any sale would have on our results of operations. We may also incur significant costs or be required to record certain charges in connection with any sale and in connection with transactions related to the deployment of the proceeds from any sale.

Additionally, uncertainty about the effect of the proposed disposition may have an adverse effect on the Company, particularly our E&P business. Although we have taken steps to reduce any adverse effects, including providing retention agreements for employees, these uncertainties may impair our ability to attract, retain and motivate key personnel and could cause partners, customers, suppliers and others that deal with our E&P business to seek to change future business relationships. Our E&P business could be harmed if, despite our retention efforts, key employees depart as a result of the proposed disposition.

An inability to access financial markets could affect the execution of our business plan. Dominion and our Virginia Power and CNG subsidiaries rely on access to short-term money markets, longer-term capital markets and banks as significant sources of liquidity for capital requirements and collateral requirements related to hedges of future gas and oil production not satisfied by the cash flows from our operations. Management believes that Dominion and our subsidiaries will maintain sufficient access to these financial markets based upon current credit ratings. However, certain disruptions outside of our control may increase our cost of borrowing or restrict our ability to access one or more financial markets. Such disruptions could include an economic downturn, the bankruptcy of an unrelated energy company or changes to our credit ratings. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled.

Changing rating agency requirements could negatively affect our growth and business strategy. As of February 1, 2007, Dominion’s senior unsecured debt is rated BBB, positive outlook, by Standard & Poor’s Ratings Services (Standard & Poor’s); Baa2, stable outlook, by Moody’s Investors Services (Moody’s); and BBB+, stable outlook, by Fitch Ratings Ltd. (Fitch). In order to maintain our current credit ratings in light of existing or future requirements, we may find it necessary to take steps or change our business plans in ways that may adversely affect our growth and earnings per share. A reduction in Dominion’s credit ratings or the credit ratings of our Virginia Power and CNG subsidiaries by Standard & Poor’s, Moody’s or Fitch could increase our borrowing costs and adversely affect operating results and could require us to post additional collateral in connection with some of our price risk management activities.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

We own our principal executive office and two other corporate offices, in Richmond, Virginia. We also lease corporate offices in other cities in which our subsidiaries operate.

Our assets consist primarily of our investments in our subsidiaries, the principal properties of which are described below and in Item 1. Business.

Substantially all of our electric utility’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds, however only $215 million of these bonds were outstanding at December 31, 2006, and the bonds will mature on July 1, 2007. Certain of our nonutility generation facilities are also subject to liens.

QUANTITIES OF GAS AND OIL PRODUCED

Quantities of gas and oil produced during each of the last three years follow:

The average realized price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other Dominion operations at market prices) during the years 2006, 2005 and 2004 was $4.41, $4.79 and $4.14, respectively. The respective average realized prices without hedging results per mcf of gas produced were $6.67, $8.01 and $5.77. The respective average realized prices for oil with hedging results were $33.42, $30.46 and $25.22 per barrel and the respective average realized prices without hedging results were $54.49, $49.48 and $35.49 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2006, 2005 and 2004 was $1.18, $1.16 and $0.91, respectively.

ITEM 3. LEGAL PROCEEDINGS

From time to time, we 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 us, 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, we are involved in various legal proceedings. We believe that the ultimate resolution of these proceedings will not have a material adverse effect on our financial position, liquidity or results of operations.

See Regulation in Item 1. Business, Future Issues and Other Matters in MD&A, and Note 23 to our Consolidated Financial Statements for additional information on various environmental, rate matters and other regulatory proceedings to which we are a party.

In March 2006, Peoples and Equitable Resources, Inc. (Equitable) filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by Equitable of all the stock of Peoples and Hope. In April 2006, Hope and Equitable filed a joint petition seeking West Virginia Commission approval of the purchase by Equitable of all of the stock of Hope. In February 2007, the administrative law judge for the Pennsylvania Commission entered an initial decision approving a proposed joint settlement and recommending approval of the sale in Pennsylvania.

Before being acquired by us, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hidalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. In April 2006, we entered into a settlement agreement with the plaintiffs resolving all of their claims against us. In May 2006, the plaintiffs non-suited Dominion with prejudice, resulting in the dismissal of the case. We remain subject, however, to a cross-claim and an indemnity claim with certain of the other defendants that were not a party to our settlement with the plaintiffs. Neither claim is material and we do not expect the resolution of these remaining claims or the settlement to have a material adverse effect on the results of operations or financial condition.

In July 1997, Jack Grynberg brought suit against CNG Producing Company, predecessor to Dominion Exploration & Pro-

duction, Inc. (DEPI), and several of its affiliates. (There are 73 defendants in this case.) The suit seeks damages for alleged fraudulent mis-measurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approximately 360 other cases in the U.S. District Court for the District of Wyoming. Parts of Mr. Grynberg’s claims were dismissed on the basis that they overlapped with Mr. Wright’s claims, which are noted below. Mr. Grynberg has filed an appeal. In October 2006, Judge Downes issued an order dismissing all claims against DEPI and its affiliates on the jurisdictional grounds that Mr. Grynberg has failed to meet his burden to prove he is the “original source” of the claims being asserted under the False Claims Act. It is expected that Mr. Grynberg will appeal this order.

In April 1998, Harrold E. (Gene) Wright filed suit against DEPI (formerly known as CNG Producing Company), a subsidiary of CNG, and numerous other companies under the False Claims Act. Mr. Wright alleged various fraudulent valuation practices in the payment of royalties due under federal oil and gas leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against us was resolved by settlement in late 2002. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied our motion to dismiss on jurisdictional grounds in January 2005. Discovery in this matter is currently underway.

In September 2006, DTI signed a Consent Order and Agreement with the Pennsylvania Department of Environmental Protection (PADEP) which supercedes a 1990 COA between the parties and has paid a penalty of $850,000. This COA was entered into as part of the settlement of an enforcement action with the PADEP and resolution of lease breaches with the Department of Conservation and Natural Resources.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

None.

Our common stock is listed on the New York Stock Exchange. At December 31, 2006, there were approximately 162,000 registered shareholders, including approximately 68,000 certificate holders. Restrictions on our payment of dividends are discussed in Note 21 to our Consolidated Financial Statements. Quarterly information concerning stock prices and dividends is disclosed in Note 30 to our Consolidated Financial Statements.

During 2006, we issued 120 shares of common stock to a former employee as a deferred payment under a 1985 perform-

ance achievement plan. These shares were not registered under the Securities Act of 1933 (Securities Act). The issuance of this stock did not involve a public offering, and is therefore exempt from registration under the Securities Act.

The following table presents certain information with respect to our common stock repurchases during the fourth quarter of 2006.

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) discusses our results of operations and general financial condition. MD&A should be read in conjunction with our Consolidated Financial Statements. The terms “Dominion,” “Company,” “we,” “our” and “us” are 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 of Dominion Resources, Inc.’s consolidated subsidiaries or operating segments or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

CONTENTS OF MD&A

The reader will find the following information in our MD&A:

FORWARD-LOOKING STATEMENTS

This report contains statements concerning our 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.

We 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:

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

Our forward-looking statements are based on our beliefs and assumptions using information available at the time the statements are made. We caution the reader not to place undue reliance on our forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. We undertake no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

INTRODUCTION

Dominion is a fully integrated gas and electric holding company headquartered in Richmond, Virginia. Our strategy is to be a leading provider of electricity, natural gas and related services to customers in the eastern region of the United States (U.S.). Our portfolio of assets includes approximately:

Our businesses are managed through four primary operating segments: Dominion Delivery, Dominion Energy, Dominion Generation and Dominion E&P. The contributions to net income by our primary operating segments are determined based on a measure of profit that we believe represents the segments’ core earnings. As a result, certain specific items attributable to those segments are not included in profit measures evaluated by management in assessing segment performance or allocating resources among the segments. Those specific items are reported in the Corporate segment.

Dominion Delivery includes our regulated electric and gas distribution and customer service businesses, as well as nonregulated retail energy marketing operations. Our electric distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina. Our gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio, Pennsylvania and West Virginia. Our nonregulated retail energy marketing operations market gas, electricity and related products and services to residential, small commercial and industrial customers in the Northeast, Mid-Atlantic and Midwest.

Revenue provided by our electric and gas distribution operations is based primarily on rates established by state regulatory authorities and state law. The profitability of these businesses is dependent on their ability, through the rates we are permitted to charge, to recover costs and earn a reasonable return on our capital investments. Variability in earnings relates largely to changes in volumes, which are primarily weather sensitive, and changes in the cost of routine maintenance and repairs (including labor and benefits). Income from retail energy marketing operations varies in connection with changes in weather and commodity prices, as well as the acquisition and loss of customers.

In March 2006, we entered into an agreement with Equitable Resources, Inc. to sell two of our wholly-owned regulated gas distribution subsidiaries, Peoples and Hope for approximately $970 million plus adjustments to reflect capital expenditures and changes in working capital. Peoples and Hope serve approximately 500,000 customer accounts in Pennsylvania and West Virginia. The transaction is expected to close by the end of second quarter of 2007, subject to state regulatory approvals in Pennsylvania and West Virginia, as well as approval under the Hart-Scott-Rodino Act.

Dominion Energy includes our regulated electric transmission, natural gas transmission pipeline and storage businesses and the Cove Point liquefied natural gas (LNG) import and storage facility. It also includes gathering and extraction activities, as well as certain Appalachian natural gas production. Dominion Energy includes producer services, which consist of aggregation of gas supply, market-based services related to gas transportation and storage, associated gas trading and results of certain energy trading activities exited in December 2004. The electric transmission business serves Virginia and northeastern North Carolina. In 2005, we became a member of PJM Interconnection, LLC (PJM), an RTO, and integrated our electric transmission facilities into PJM wholesale electricity markets. The gas transmission pipeline and storage business serves our gas distribution businesses and other customers in the Northeast, Mid-Atlantic and Midwest.

Revenue provided by our regulated electric and gas transmission operations and the LNG facility is based primarily on rates established by the Federal Energy Regulatory Commission

(FERC). The profitability of these businesses is dependent on our ability, through the rates we are permitted to charge, to recover costs and earn a reasonable return on our capital investments. Variability in earnings results from changes in rates and the demand for services, which is primarily weather dependent.

Earnings from Dominion Energy’s nonregulated businesses are subject to variability associated with changes in commodity prices. Dominion Energy’s nonregulated businesses use physical and financial arrangements to attempt to hedge this price risk. Certain hedging and trading activities may require cash deposits to satisfy collateral requirements. Variability in earnings also results from changes in operating and maintenance expenditures (including labor and benefits).

Dominion Generation includes the generation operations of our electric utility and merchant fleet and utility energy supply, energy marketing and price risk management activities for our generation assets. Our generation mix is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. The generation facilities of our electric utility fleet are located in Virginia, West Virginia and North Carolina. The generation facilities of our merchant fleet are located in Connecticut, Illinois, Indiana, Massachusetts, Ohio, Pennsylvania, Rhode Island, West Virginia and Wisconsin.

Dominion Generation’s earnings primarily result from the generation and sale of electricity. Due to 2004 deregulation legislation, revenues for serving Virginia jurisdictional retail load are based on capped rates through 2010 and fuel costs for the utility fleet, including power purchases, are subject to fixed rate recovery provisions until July 1, 2007, at which time fuel rates will be adjusted annually as discussed in Status of Electric Restructuring in Virginia under Future Issues and Other Matters. Changes in our utility operating costs, particularly with respect to fuel and purchased power, relative to costs used to establish capped rates, will impact our earnings.

Variability in earnings provided by the merchant fleet relates to changes in market-based prices received for electricity and the demand for electricity, which is primarily weather driven. We manage price volatility by hedging a substantial portion of our expected sales. 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.

In December 2006, we reached an agreement with an entity jointly owned by Tenaska Power Fund, L.P. and Warburg Pincus LLC to sell three of our natural gas-fired merchant generation peaking facilities (Peaker facilities). Peaking facilities are used during times of high electricity demand, generally in the summer months. The Peaker facilities are:

The sale is expected to result in proceeds of approximately $256 million and should close in the first quarter of 2007, pending regulatory approval by FERC. We have obtained approval from the Federal Trade Commission. No state regulatory approvals are required.

We offered the facilities for sale following a review of our portfolio of assets. We have decided not to sell a fourth merchant generation facility, State Line, a 515 Mw coal-fired facility in Hammond, Indiana.

Dominion E&P includes our gas and oil exploration, development and production business. Operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico, West Texas, Mid-Continent, the Rockies and Appalachia, as well as the Western Canadian Sedimentary Basin.

Dominion E&P generates income from the sale of natural gas and oil we produce from our reserves. Variability in earnings relates primarily to changes in commodity prices, which are market-based, and production volumes, which are impacted by numerous factors including drilling success, timing of development projects and external factors such as storm-related damage caused by hurricanes. We attempt to manage commodity price volatility by hedging a substantial portion of our expected production. These hedging activities may require cash deposits to satisfy collateral requirements.

In November 2006, we announced our decision to pursue the sale of all of our oil and natural gas E&P operations and assets, with the exception of those located in the Appalachian Basin. As of December 31, 2006, our natural gas and oil assets—excluding the Appalachian Basin—included about 5.5 trillion cubic feet of proved reserves. The Appalachian assets that we would retain constitute approximately 15% of our total reserves as of December 31, 2006.

Corporate includes our corporate, service company and other operations (including unallocated debt), corporate-wide commodity risk management services, the remaining assets of DCI, which are in the process of being divested, the net impact of our discontinued telecommunications operations that were sold in May 2004 and the net impact of the discontinued operations of the Peaker facilities. In addition, Corporate includes specific items attributable to our operating segments that have been excluded from the profit measures evaluated by management, either in assessing segment performance or in allocating resources among the segments.

Outlook

A sale of substantially all of our E&P business would allow us to focus on growing our electric generating and energy distribution, transmission and storage businesses and realign our operations and risk profile more closely with our peer investment group of utilities. If a sale is completed, we would use the net cash proceeds to reduce debt and maintain or improve our existing credit ratings. We would also expect to repurchase shares of our common stock and/or acquire select assets to complement our remaining businesses. By redeploying net cash proceeds to debt reduction, stock buybacks and expansion of our remaining businesses, we believe that shareholders would see solid, reliable growth from a complementary set of assets. Our objective is to grow consolidated earnings at a long-term average annual rate of 4 to 6 percent following any E&P sale. Closing of any sale or sales is targeted for mid-2007.

While a sale would likely dilute consolidated earnings per share in the short term, we believe a sale will result in more stable and predictable earnings that are less sensitive to changes in commodity prices, and could result in an increased dividend. Our Board of Directors will address the issue of a possible change in the dividend policy following a sale. In total, we believe that our strategic repositioning, once complete, will provide the necessary platform to enhance shareholder value.

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

ACCOUNTING MATTERS

Critical Accounting Policies and Estimates

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

ACCOUNTING FOR DERIVATIVE CONTRACTS AT FAIR VALUE

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

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

develop the estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on a contract’s estimated fair value.

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

USE OF ESTIMATES IN GOODWILL IMPAIRMENT TESTING

As of December 31, 2006, we reported $4.3 billion of goodwill in our Consolidated Balance Sheet, a significant portion of which resulted from the acquisition of Consolidated Natural Gas Company (CNG) in 2000. Substantially all of this goodwill is allocated to our Generation, Transmission, Delivery and E&P reporting units. In April of each year, we test our goodwill for potential impairment, and perform additional tests more frequently if impairment indicators are present. The 2006, 2005 and 2004 annual tests did not result in the recognition of any goodwill impairment, as the estimated fair values of our reporting units exceeded their respective carrying amounts.

We estimate the fair value of our reporting units by using a combination of discounted cash flow analyses, based on our internal five-year strategic plan, and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. These calculations are dependent on subjective factors such as our 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 our estimates of future cash flows, could result in a future impairment of goodwill. Although we have 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 annual test 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 our cash flow estimates are based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed.

In conjunction with the results of a review of our portfolio of assets, the Peaker facilities, with a combined carrying amount of $504 million, were marketed for sale in the third quarter of 2006. An impairment analysis performed in the third quarter of 2006 indicated that the carrying amount of each of the Peaker facilities was recoverable as the expected undiscounted cash flows, probability weighted to reflect both continued use and possible sale scenarios, exceeded the carrying amount. In December 2006, we reached an agreement to sell the Peaker facilities and accordingly, we reduced their carrying amounts to fair value less cost to sell and classified them as held for sale in our Consolidated Balance Sheet. Also in the fourth quarter of 2006, in conjunction with the review of our assets, a decision was made to no longer pursue the development of a gas transmission pipeline project with capitalized construction costs of $28 million. The pipeline project was previously tested for impairment during 2005. The results of our analysis in 2005 indicated that this asset was not impaired. Impairment charges of $280 million ($181 million after-tax) were recorded in December 2006 related to the Peaker facilities and the transmission pipeline project.

Also in 2006, a natural gas-fired merchant generation facility project, with a carrying amount of $460 million, was tested for impairment. The results of our analysis indicated that this carrying amount, as well as the estimated cost to complete, were recoverable.

In 2005, we tested a group of gas and steam electric turbines held for future development with a carrying amount of $187 million for impairment. The results of our analysis indicated that this carrying amount was recoverable. In 2004, we did not test any significant long-lived assets or asset groups for impairment as no circumstances arose that indicated an impairment may exist.

ASSET RETIREMENT OBLIGATIONS

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

accrete the ARO liability to reflect the passage of time. In 2006, 2005 and 2004, we recognized $109 million, $102 million and $91 million, respectively, of accretion, and expect to incur $82 million in 2007.

A significant portion of our AROs relates to the future decommissioning of our nuclear facilities. At December 31, 2006, nuclear decommissioning AROs, which are reported in the Dominion Generation segment, totaled $1.4 billion, representing approximately 73% of our total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with our nuclear decommissioning obligations.

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

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of our nuclear facilities. In 2006, we lowered the cost escalation rate assumptions used in the ARO calculation by 0.72% due to projected reductions in both general and decommissioning specific inflation rates, resulting in a $481 million decrease in our nuclear decommissioning AROs.

EMPLOYEE BENEFIT PLANS

We sponsor 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 rate of return on plan assets, discount rates applied to benefit obligations and the anticipated rate of increase in health care costs and participant compensation, also have a significant impact on employee benefit costs. The impact on pension and other postretirement benefit plan obligations associated with changes in these factors is generally recognized in our 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 medical cost trend rates are critical assumptions. We determine the expected long-term rates of return on plan assets for pension plans and other postretirement benefit plans by using a combination of:

Assisted by an independent actuary, we develop assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. We calculated our pension cost using an expected return on plan assets assumption of 8.75% for 2006, 2005 and 2004. We calculated our 2006 and 2005 other postretirement benefit cost using an expected return on plan assets assumption of 8.00% compared to 7.79% for 2004. 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.

We determine discount rates from analyses performed by a third-party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under our plans. The discount rates used to calculate 2006 pension cost and other postretirement benefit cost were 5.60% and 5.50%, respectively, compared to the 6.00% and 6.25% discount rates used to calculate 2005 and 2004 pension and other postretirement benefit costs, respectively. Lower long-term bond yields were the primary reason for the decline in the discount rate from 2005 to 2006. We selected discount rates of 6.20% and 6.10% for determining our December 31, 2006 projected pension and postretirement benefit obligations, respectively.

We establish the medical cost trend rate assumption based on analyses performed by a third-party actuarial firm of various factors including the specific provisions of our medical plans, actual cost trends experienced and projected, and demographics of plan participants. Our medical cost trend rate assumption as of December 31, 2006 is 9.00% and is expected to gradually decrease to 5.00% in later years.

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, a 0.25% decrease in the discount rate would increase our projected pension benefit obligation by $122 million and would increase our accumulated postretirement benefit obligation by $38 million at December 31, 2006.

ACCOUNTING FOR REGULATED OPERATIONS

The accounting for our regulated electric and gas operations differs from the accounting for nonregulated operations in that we are required to reflect the effect of rate regulation in our Consolidated Financial Statements. 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, we defer these costs as regulatory assets that otherwise would be expensed by nonregulated companies. Likewise, we recognize regulatory liabilities when it is probable that regulators will require customer refunds through future rates and when revenue is collected from customers for expenditures that are not yet incurred. Regulatory assets are amortized into expense and regulatory liabilities are amortized into income over the recovery period authorized by the regulator.

We evaluate whether or not recovery of our regulatory assets through future rates is probable and make various assumptions in our 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, $166 million of our regulatory assets were written off as a result of the pending sale of Peoples and Hope since the recovery of those assets is no longer probable. We currently believe the recovery of our remaining regulatory assets is probable. See Notes 2 and 14 to our Consolidated Financial Statements.

ACCOUNTING FOR GAS AND OIL OPERATIONS

We follow the full cost method of accounting for gas and oil E&P activities prescribed by the Securities and Exchange Commission (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. The depletable base of costs 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. Capitalized costs in the depletable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves, assuming period-end pricing adjusted for any cash flow hedges in place. We perform the ceiling test quarterly, on a country-by-country basis, and would recognize 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 country.

Our 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. Our estimated proved reserves as of December 31, 2006 are based upon studies for each of our properties prepared by our

staff engineers and audited by Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. Given the volatility of natural gas and oil prices, it is possible that our 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 our estimates or assumptions in the future and revisions to the value of our 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 and 29 to our Consolidated Financial Statements.

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.

Through December 31, 2006, we have established liabilities for tax-related contingencies in accordance with Statement of Financial Accounting Standards (SFAS) No. 5, Accounting for Contingencies, and reviewed them in light of changing facts and circumstances. However, as discussed in Note 4 to our Consolidated Financial Statements, effective January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation No. 48, Accounting for Uncertainty in Income Taxes (FIN 48). Taking into consideration the uncertainty and judgment involved in the determination and filing of income taxes, FIN 48 establishes standards for recognition and measurement, in financial statements, of positions taken, or expected to be taken, by an entity in its income tax returns. Positions taken by an entity in its income tax returns that are recognized in the financial statements must satisfy a more-likely than-not recognition threshold, assuming that the position will be examined by taxing authorities with full knowledge of all relevant information.

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

Other

ACCOUNTING STANDARDS

During 2006, 2005 and 2004, we were required to adopt several new accounting standards, which are discussed in Note 3 to our Consolidated Financial Statements. Our adoption of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans on December 31, 2006 affected the comparability of our Consolidated Balance Sheet at December 31, 2006 to prior periods. Under SFAS No. 158, our

Consolidated Balance Sheet now reflects the overfunded or underfunded status of our defined benefit plans as an asset or a liability, respectively, with previously unrecognized net actuarial gains or losses, prior service costs or credits and transition obligations recognized as a component of either AOCI or regulatory assets or liabilities. See Note 4 to our Consolidated Financial Statements for a discussion of recently issued accounting standards that will be adopted in the future.

DOMINION CLEARINGHOUSE

During the fourth quarter of 2004, we performed an evaluation of our Dominion Clearinghouse (Clearinghouse) trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of our assets. In January 2005, in connection with the reorganization, commodity derivative contracts held by the Clearinghouse were assessed to determine if they contribute to the optimization of our assets. As a result of this review, certain commodity derivative contracts previously designated as held for trading purposes were redesignated as held for non-trading purposes. Under our derivative income statement classification policy described in Note 2 to our Consolidated Financial Statements, all changes in fair value, including amounts realized upon settlement, related to the reclassified contracts were previously presented in operating revenue on a net basis. Upon redesignation as non-trading, all unrealized changes in fair value and settlements related to those derivative contracts that are financially settled are reported in other operations and maintenance expense. In addition, all physically-settled sales contracts are presented in operating revenue and all physically-settled purchase contracts are presented in operating expense in our Consolidated Statements of Income.

RESULTS OF OPERATIONS

Presented below is a summary of our consolidated results:

Overview

2006 VS. 2005

Net income increased 34% to $1.4 billion. Favorable drivers included increased gas and oil production, higher realized prices from our merchant generation business, an increased contribution from our nonregulated retail energy marketing operations, higher business interruption insurance proceeds received in 2006 than in 2005 and the absence of losses incurred in 2005 due to the discontinuance of hedge accounting for certain gas and oil hedges resulting from hurricane-related interruptions of gas and oil production in the Gulf of Mexico. These favorable drivers were partially offset by an impairment charge related to the Peaker facilities, milder weather in our gas and electric service territories, lower realized gas prices for our E&P operations and a

reduction in gains from sales of emissions allowances held for consumption.

2005 VS. 2004

Our 2005 results were significantly impacted by Hurricanes Katrina and Rita (2005 hurricanes), which struck the Gulf Coast area in late August and late September 2005, respectively. Due to the hurricanes, our production assets in the Gulf of Mexico and, to a lesser extent, southern Louisiana were temporarily shut in. The interruption in gas and oil production resulted in a $272 million after-tax loss related to the discontinuance of hedge accounting for certain gas and oil hedges. Results were also impacted by delays in production caused by damage to third-party downstream infrastructure.

Our 2005 results were also negatively impacted by increased fuel and purchased power expenses incurred by our electric utility operations primarily as a result of higher commodity prices. These negatives were partially offset by higher realized gas and oil prices for our E&P operations, gains on the sale of emissions allowances and a higher contribution from merchant generation operations, primarily reflecting the benefit of two acquisitions during 2005. In January 2005, we completed the acquisition of three fossil-fired power stations with generating capacity of more than 2,700 Mw (Dominion New England) and in July 2005, we completed the acquisition of the 556 Mw Kewaunee nuclear power station (Kewaunee).

Analysis of Consolidated Operations

Presented below are selected amounts related to our results of operations: