Item 1. Business

THE COMPANY

Dominion Resources, Inc. (Dominion), headquartered in Richmond, Virginia and incorporated in Virginia in 1983, is one of the nation’s largest producers and transporters of energy. Our strategy is to be a leading provider of electricity, natural gas and related services to customers primarily in the eastern region of the U.S. Our portfolio of assets includes approximately 27,000 Mw of generation, 6,000 miles of electric transmission lines, 56,000 miles of electric distribution lines in Virginia and North Carolina, 14,000 miles of natural gas transmission, gathering and storage pipeline, 28,000 miles of gas distribution pipeline, exclusive of service lines of two inches in diameter or less, and 1.2 trillion cubic feet equivalent (Tcfe) of natural gas and oil reserves. Dominion also owns the nation’s largest underground natural gas storage system and operates over 975 bcf of storage capacity and serves retail energy customers in twelve states.

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 or more 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), Dominion Energy, Inc. (DEI), Dominion Transmission, Inc. (DTI), Virginia Power Energy Marketing, Inc. (VPEM), Dominion Exploration and Production, Inc. (DEPI), The East Ohio Gas Company (Dominion East Ohio), Dominion Field Services, Inc. (DFS), Dominion Retail, Inc. (Dominion Retail) and Dominion Resources Services, Inc. (DRS). Virginia Power is a regulated public utility that generates, transmits and distributes electricity for sale in Virginia and northeastern North Carolina. As of December 31, 2008, Virginia Power served approximately 2.4 million retail customer accounts, including governmental agencies, as well as wholesale customers such as rural electric cooperatives and municipalities. DEI is involved in merchant generation, energy marketing and price risk management activities and natural gas and oil exploration and production in the Appalachian basin of the U.S. DTI operates a regulated interstate natural gas transmission pipeline and underground storage system in the Northeast, mid-Atlantic and Midwest states and is engaged in the production, gathering and extraction of natural gas in the Appalachian basin. VPEM provides fuel, gas supply management and price risk management services to other Dominion affiliates and engages in energy trading activities. DEPI explores for, develops and produces natural gas and oil in the Appalachian basin of the U.S. DFS is involved in the gathering and aggregation of Appalachian natural gas supply and provides various marketing-related services to its customers. Dominion Retail markets gas, electricity and related products and services to residential and small commercial and industrial customers. As of December 31, 2008, these nonregulated retail energy marketing operations served approximately 1.6 million residential and small commercial and industrial customer accounts in the Northeast, mid-Atlantic and Midwest regions of the U.S and in Texas. DRS

provides accounting, legal, finance and certain administrative and technical services to our subsidiaries. In addition, all of our officers are employees of DRS.

As of December 31, 2008, our regulated gas distribution subsidiaries, Dominion East Ohio, Peoples Natural Gas Company (Peoples) and Hope Gas, Inc. (Hope), served approximately 1.7 million residential, commercial and industrial gas sales and transportation customer accounts in Ohio, Pennsylvania and West Virginia. Of these customers, approximately 500,000 are served by Peoples and Hope, which are held for sale as discussed in Acquisitions and Dispositions. We also operate a liquefied natural gas (LNG) import and storage facility in Maryland.

As of December 31, 2008, we had approximately 18,000 full-time employees. Approximately 6,700 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 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 to 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.

ACQUISITIONS AND DISPOSITIONS

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

ACQUISITION OF PABLO ENERGY, LLC

In February 2006, we completed the acquisition of Pablo Energy, LLC (Pablo) for approximately $92 million in cash. Pablo held producing and other properties located in the Texas Panhandle area. Following the disposition of these, and all of our other non-Appalachian E&P operations during 2007, the historical results of these operations are included in our Corporate and Other segment.

ACQUISITION OF KEWAUNEE NUCLEAR POWER STATION

In July 2005, we completed the acquisition of the 556 Mw Kewaunee nuclear power station (Kewaunee), located in

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northeastern Wisconsin, from Wisconsin Public Service Corporation, a subsidiary of WPS Resources Corporation, and Wisconsin Power and Light Company, a subsidiary of Alliant Energy Corporation for approximately $192 million in cash. The operations of Kewaunee are included in our Dominion Generation operating segment.

ACQUISITION OF USGEN POWER STATIONS

In January 2005, we completed the acquisition of three fossil-fuel fired generation facilities from USGen New England, Inc. for $642 million in cash. The facilities include the 1,568 Mw Brayton Point power station (Brayton Point) in Somerset, Massachusetts; the 754 Mw Salem Harbor power station (Salem Harbor) in Salem, Massachusetts; and the 432 Mw Manchester Street power station (Manchester Street) in Providence, Rhode Island. The operations of these facilities are included in our Dominion Generation operating segment.

ASSIGNMENT OF MARCELLUS ACREAGE

In 2008, we completed a transaction with Antero Resources (Antero) to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. We received proceeds of approximately $347 million and recognized $4 million of associated closing costs. Under the agreement, we will receive a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. We will retain the drilling rights in traditional formations both above and below the Marcellus Shale interval and will continue our conventional drilling program on the acreage.

SALE OF E&P PROPERTIES

In 2007, we completed the sale of our non-Appalachian natural gas and oil E&P operations and assets for approximately $13.9 billion. A more detailed description of the disposition can be found in Note 5 to our Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data.

In 2006, we received approximately $393 million of proceeds from sales of certain gas and oil properties, primarily resulting from the sale of certain properties located in Texas and New Mexico and in December 2004, we sold the majority of our natural gas and oil assets in British Columbia, Canada for $476 million.

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

SALE OF MERCHANT FACILITIES

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

SALE OF DRESDEN

In September 2007, we completed the sale of the partially completed Dresden Energy merchant generation facility (Dresden) to AEP Generating Company for $85 million.

SALE OF CERTAIN DOMINION CAPITAL, INC. (DCI) OPERATIONS

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

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

PLANNED SALES

In addition to the completed acquisitions and divestitures above, in March 2006, we entered into an agreement with Equitable to sell two of our wholly-owned regulated gas distribution subsidiaries, Peoples and Hope. Peoples and Hope serve approximately 500,000 customer accounts in Pennsylvania and West Virginia. This sale was subject to regulatory approvals in the states in which the companies operate, as well as antitrust clearance under the Hart-Scott-Rodino Act (HSR Act). In January 2008, Dominion and Equitable announced the termination of that agreement, primarily due to the continued delays in achieving final regulatory approvals. We continued to seek other offers for the purchase of these utilities.

In July 2008, we announced that we entered into an agreement with a subsidiary of Babcock & Brown Infrastructure Fund North America (BBIFNA) to sell Peoples and Hope for approximately $910 million, subject to adjustments to reflect levels of capital expenditures and changes in working capital. In September 2008, Peoples and BBIFNA filed a joint petition with the Pennsylvania Commission seeking approval of the purchase by BBIFNA of all of the stock of Peoples. In October 2008, Hope and BBIFNA filed a joint petition seeking West Virginia Commission approval of the purchase by BBIFNA of all of the stock of Hope. In September 2008, Dominion and BBIFNA each filed a Premerger Notification and Report Form with the U.S. Department of Justice (DOJ) and the Federal Trade Commission under the HSR Act. In October 2008, the waiting period under the HSR Act related to the proposed sale of Peoples and Hope to BBIFNA expired. The transaction is expected to close in 2009, subject to regulatory approvals in Pennsylvania and West Virginia as well as clearance under the Exon-Florio provision of the Omnibus Trade and Competitiveness Act. We expect to use the after-tax proceeds from the sale to reduce our debt. The results of Peoples’ and Hope’s operations are included in our Corporate and Other segment.

OPERATING SEGMENTS

We manage our daily operations through three primary operating segments: Dominion Virginia Power (DVP), Dominion Energy and Dominion Generation. We also report a Corporate and Other segment that includes our corporate, service company and other functions and the net impact of certain operations disposed of or to be disposed of, which are discussed in Note 5 to our Consolidated Financial Statements. Corporate and Other also includes specific items attributable to our operating segments,

that are not included in profit measures evaluated by executive management, in assessing the segments’ performance or allocating resources among the segments.

While we manage our daily operations through our operating segments as described below, 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 Notes 1 and 26 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.

DVP

DVP includes our regulated electric transmission, distribution and customer service operations, as well as our nonregulated retail energy marketing operations. Our electric transmission and distribution operations serve residential, commercial, industrial and governmental customers in Virginia and northeastern North Carolina.

Revenue provided by our electric distribution operations is based primarily on rates established by state regulatory authorities and state law. Changes in revenue are driven primarily by weather, customer growth and other factors impacting consumption such as the economy and energy conservation. Operationally, electric distribution continues to focus on improving service levels while striving to reduce costs and link investments to operational results. As part of this continued focus, we have implemented an asset management process to ensure that we are optimizing our investments to balance cost, performance and risk. We are also using technology to enhance customer service options. As we move toward the future, safety, operational performance and customer relationships will remain as key focal areas. Variability in earnings results from changes in rates, the demand for services and operating and maintenance expenditures.

As discussed in Status of Electric Regulation in Virginia under Regulation, the Virginia General Assembly enacted legislation in April 2007 that institutes a modified cost-of-service rate model for the Virginia jurisdiction of our utility operations, subject to base rate caps in effect through December 31, 2008. We currently anticipate that the 2009 base rate review will result in an increase in rates, however we cannot predict the outcome of future rate actions at this time.

Revenue provided by our electric transmission operations is based primarily on rates approved by FERC. The profitability of this business is dependent on its ability, through the rates it is permitted to charge, to recover costs and earn a reasonable return on its capital investments. Variability in earnings results from changes in rates and the timing of property additions, retirements and depreciation.

In April 2008, FERC granted an application by our electric transmission operations to establish a forward-looking formula rate mechanism that will update transmission rates on an annual basis and approved a return on equity (ROE) of 11.4% on the common equity base of these operations, effective as of January 1, 2008. The FERC ruling did not materially impact our results of operations; however, going forward the FERC-approved formula method will allow us to earn a more current return on our growing investment in electric transmission infrastructure. In addition, in August 2008, FERC granted an application by our electric

transmission operations requesting a revision to our cost of service to reflect an additional ROE incentive adder for eleven electric transmission enhancement projects and approved an incentive of 1.5% for four of the projects and an incentive of 1.25% for the other seven. See Federal Regulations in Regulation for additional information.

DVP is a member of PJM, a regional transmission organization (RTO), and our electric transmission facilities are integrated into PJM wholesale electricity markets. Consistent with the increased authority given to the North American Electric Reliability Corporation (NERC) by the Energy Policy Act of 2005 (EPACT), we are committed to meeting NERC standards, modernizing our infrastructure and maintaining superior system reliability. We will continue to focus on safety, operational performance and execution of PJM’s Regional Transmission Expansion Plan (RTEP).

Operationally, DVP continues to enhance the customer experience through solid reliability performance and by providing our customers the ability to manage their accounts on-line. At the end of 2008, over 600,000 of DVP’s customers were signed up to manage their account on-line through dom.com and over 2 million transactions were performed in 2008. This reflects a transaction increase of 28% over 2007. Customers typically use the Internet for routine billing and payment transactions; however, we expect the addition of new 2008 options like connecting and disconnecting service and reporting outages and obtaining outage updates to continue to increase on-line usage.

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

COMPETITION

Within DVP’s service territory in Virginia and North Carolina, there is no competition for electric distribution service. Additionally, since our electric transmission facilities are integrated into PJM, our electric transmission services are administered by PJM and are not subject to competition in relation to transmission service provided to customers within the PJM region. In our transmission and distribution operations, we are seeing continued growth in new customers.

Our retail energy marketing operations compete against incumbent utilities and other energy marketers in nonregulated energy markets for natural gas and electricity.

REGULATION

DVP’s electric retail service, including the rates it may charge to jurisdictional customers, is subject to regulation by the Virginia Commission and the North Carolina Commission. DVP’s electric transmission rates, tariffs and terms of service are subject to

regulation by FERC. Electric transmission siting authority remains the jurisdiction of the Virginia and North Carolina Commissions. However, EPACT provides FERC with certain backstop authority for transmission siting. See State Regulations and Federal Regulations in Regulation for additional information.

PROPERTIES

DVP 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 DVP’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 own and maintain our electric transmission facilities, they are a part of PJM, which coordinates the planning, operation, emergency assistance, and exchange of capacity and energy for such facilities.

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

The first project is an approximately 270-mile 500-kV transmission line that begins in southwestern Pennsylvania, crosses West Virginia, and terminates in northern Virginia, of which we will construct approximately 65 miles in Virginia (Meadow Brook-to-Loudoun line) and a subsidiary of Allegheny Energy, Inc. (Trans-Allegheny Interstate Line Company) will construct the remainder. In October 2008, the Virginia Commission authorized construction of the Meadow Brook-to-Loudoun line and affirmed the 65-mile route we proposed for the line which is adjacent to, or within, existing transmission line right-of-ways. The Virginia Commission’s approval of the Meadow Brook-to-Loudoun line was conditioned on the respective state commission approvals of both the West Virginia and Pennsylvania portions of the transmission line. The West Virginia Commission’s approval of Trans-Allegheny Interstate Line Company’s application became effective in February 2009 and the Pennsylvania Commission granted approval in December 2008. In February 2009, Petitions for Appeal of the Virginia Commission’s approval of the Meadow Brook-to-Loudoun line were filed with the Supreme Court of Virginia by the Piedmont Environmental Council and others. The Meadow Brook-to-Loudoun line is expected to cost approximately $255 million and, subject to the receipt of all regulatory approvals, is expected to be completed in June 2011.

The second project is an approximately 60-mile 500-kV transmission line that we will construct in southeastern Virginia (Carson-to-Suffolk line). In October 2008, the Virginia Commission authorized the construction of the Carson-to-Suffolk line. This project is estimated to cost $224 million and is expected to be completed in June 2011. 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 are subject to applicable state and federal permits and approvals.

In addition, DVP’s electric distribution network includes approximately 56,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The

grants for most of our electric lines contain right-of-ways that have been obtained from the apparent owner of real estate, but underlying titles have not been examined. Where right-of-ways have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly-owned property, where permission to operate can be revoked.

SOURCES OF ENERGY SUPPLY

DVP’s utility operations supply of electricity to serve customers is produced or procured by Dominion Generation. See Dominion Generation for additional information. DVP’s nonregulated retail energy marketing operations supply of electricity to serve its customers is procured through market wholesalers and RTO or independent system operator (ISO) transactions and its supply of gas to serve its customers is procured through market wholesalers or by Dominion Energy. See Dominion Energy for additional information.

SEASONALITY

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

Dominion Energy

Dominion Energy includes our Ohio regulated natural gas distribution company, regulated gas transmission pipeline and storage operations, regulated LNG operations and our Appalachian natural gas E&P business. Dominion Energy also includes producer services, which aggregates natural gas supply, engages in natural gas trading and marketing activities and natural gas supply management and provides price risk management services to Dominion affiliates.

The gas transmission pipeline and storage business serves gas distribution businesses and other customers in the Northeast, mid-Atlantic and Midwest. Included in our gas transmission pipeline and storage business is our gas gathering and extraction activity, which sells extracted products at market rates. Revenue provided by our regulated gas transmission and storage, and LNG operations is based primarily on rates established by FERC. Our gas distribution operations serve residential, commercial and industrial gas sales and transportation customers in Ohio. Revenue provided by our gas distribution operations is based primarily on rates established by the Ohio Commission. 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 operating and maintenance expenditures, as well as, changes in rates and the demand for services, which can be dependent on weather and changes in commodity prices.

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

contractual arrangements. Approximately ten to twenty percent of these agreements are subject to renewal each year.

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

Our Appalachian E&P business generates income from the sale of natural gas and oil we produce from our reserves, including fixed-term overriding royalty interests formerly associated with our volumetric production payment (VPP) agreements discussed in Note 12 to our Consolidated Financial Statements. Variability in earnings relates to changes in commodity prices, which are largely market based, production volumes, which are impacted by numerous factors including drilling success and timing of development projects, and drilling costs which may be impacted by drilling rig availability and other external factors. Production from fixed-term overriding royalty interests formerly associated with our VPP agreements is expected to decline 87% in 2009, reflecting the expiration of these interests in February 2009. We manage commodity price volatility by hedging a substantial portion of our near-term expected production, which should help mitigate the adverse impact on earnings from recent declines in gas and oil prices, such as those experienced in late 2008. These hedging activities may require cash deposits to satisfy collateral requirements. Our Appalachian E&P business added 149 bcfe to its gas and oil reserves as a result of its drilling program during 2008, as compared to production of 46.9 bcfe in 2008, excluding production from fixed-term overriding royalty interests.

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

COMPETITION

Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies. 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.

With respect to our Ohio natural gas distribution subsidiary, 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 Ohio Commission. See Regulation—State Regulations—Gas for additional information.

REGULATION

Dominion Energy’s natural gas transmission pipeline, storage and LNG operations are regulated primarily by FERC. Dominion

Energy’s gas distribution service, including the rates that it may charge customers, is regulated by the Ohio Commission. See State Regulations and Federal Regulations in Regulation for more information.

PROPERTIES

Dominion Energy’s gas distribution network is located in the state of Ohio. This network involves approximately 18,500 miles of pipe, exclusive of service lines of two inches in diameter or less. The rights-of-way grants for many natural gas pipelines have been obtained from the actual owner of real estate, as underlying titles have been examined. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many natural gas pipelines are on publicly-owned property, where company rights and actions are determined on a case-by-case basis, with results that range from reimbursed relocation to revocation of permission to operate.

Dominion Energy has approximately 11,890 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia. Dominion Energy operates 20 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with almost 2,000 storage wells and approximately 345,600 acres of operated leaseholds.

The total designed capacity of the underground storage fields operated by Dominion Energy is approximately 942 bcf. Certain storage fields are jointly-owned and operated by Dominion Energy. The capacity of those fields owned by 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 123 compressor stations with more than 706,000 installed compressor horsepower.

Dominion Energy also owns about 1.2 Tcfe of proved natural gas and oil reserves and produces approximately 128 million cubic feet equivalent of natural gas and oil per day from its leasehold acreage and facility investments in Appalachia.

In 2006, FERC approved the proposed expansion of our Cove Point terminal and DTI pipeline and the commencement of construction of such project. Such expansion included the installation of two new LNG storage tanks at our Cove Point terminal, each capable of storing 160,000 cubic meters of LNG and expansion of our Cove Point pipeline to approximately 1,800,000 dekatherms per day. In addition, our DTI gas pipeline and storage system would be expanded by building 81 miles of pipeline, two compressor stations in Pennsylvania and other upgrades.

In 2007, Washington Gas Light Company (WGL) petitioned the U.S. Court of Appeals for the District of Columbia (D.C. Appeals Court) for review of FERC’s orders. Prior to FERC’s final order approving the Cove Point expansion, WGL had asked FERC to delay its approval based on its assertion that leaks on its system were caused by the composition of gas received from the Cove Point pipeline. FERC rejected WGL’s claims, concluding that the leaks were a result of other defects in WGL’s system, not the composition of the LNG received from Cove Point. In July 2008, the D.C. Appeals Court affirmed FERC’s rulings on a number of important issues, including FERC’s findings that the leaks were the result of defects on WGL’s system and that we are not responsible for repairs. However, the court vacated FERC’s

orders to the extent that these orders approved the expansion and remanded the case back to FERC so that FERC could more fully explain whether the expansion could go forward without causing unsafe leakage on WGL’s system.

In an order on remand issued in October 2008, FERC responded to the D.C. Appeals Court by reissuing authorizations for the construction and operation of the Cove Point and DTI facilities. FERC also capped deliveries from the Cove Point pipeline into Columbia Gas Transmission Corporation (Columbia) at currently authorized levels. FERC took this step to ensure that WGL would not be exposed to greater deliveries of regasified LNG via Columbia than it can currently receive. This limitation on deliveries to Columbia will have no impact on Cove Point’s firm service obligations. In November 2008, WGL requested rehearing of the order on remand. In an order on rehearing in January 2009, FERC upheld its decision reauthorizing construction and operation of the Cove Point LNG expansion. The DTI facilities associated with the Cove Point expansion project were placed into service in December 2008. It is anticipated that the expanded Cove Point facilities will be fully placed into service in the first quarter of 2009.

We previously entered into an agreement with Antero to assign natural gas drilling rights on approximately 205,000 Appalachian Basin net acres for approximately $552 million; however, due to Antero’s difficulty in obtaining follow-on financing, the amount assigned was reduced. In September 2008, we completed a transaction with Antero to assign drilling rights to approximately 117,000 acres in the Marcellus Shale formation located in West Virginia and Pennsylvania. We received proceeds of approximately $347 million and recognized $4 million of associated closing costs. Under the agreement, we will receive a 7.5% overriding royalty interest on future natural gas production from the assigned acreage. We will retain the drilling rights in traditional formations both above and below the Marcellus Shale interval and will continue our conventional drilling program on the acreage. We control drilling rights on substantial acreage in the Marcellus Shale formation, and expect to pursue similar transactions in the future.

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

We have also announced the proposed development of the Dominion Keystone Project, an expansion of the DTI system that would transport new natural gas supplies from the Appalachian Basin to markets throughout the eastern U.S. In December 2008, we terminated our agreement with Antero, under which Antero was to join DEPI as an anchor tenant of the Dominion Keystone Project. We are currently in discussions regarding the continued development of the Dominion Keystone Project. Project timing is subject to producer drilling plans in the Appalachian Basin, as well as customer demand throughout the mid-Atlantic and Northeast regions.

SOURCES OF ENERGY SUPPLY

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, including the proposed Rockies Express East pipeline 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 transmission capacity. Dominion Energy’s natural gas supply is obtained from various sources including our own equity production, purchases from major and independent producers in the Mid-Continent and Gulf Coast regions, local producers in the Appalachian area and gas marketers.

SEASONALITY

Dominion Energy’s natural gas distribution business earnings vary seasonally, as a result of the impact of changes in temperature on demand by residential and commercial customers for gas to meet heating needs. Historically, the majority of these earnings have been generated during the heating season, which is generally from November to March, however implementation of the SFV rate design should reduce the earnings impact of weather-related fluctuations. Demand for services at our pipelines and storage business can also be weather sensitive. Dominion Energy’s Appalachian E&P business can be impacted by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for our unhedged natural gas and oil production, can be impacted by seasonal weather changes and by the effects of weather on operations. Our producer services business is affected by seasonal changes in the prices of commodities that it transports, stores and actively markets and trades.

Dominion Generation

Dominion Generation includes the generation operations of our merchant fleet and regulated electric utility, as well as energy marketing and price risk management activities for our generation assets. Our utility generation operations primarily serve the supply requirements for our DVP segment’s utility customers. Our generation mix is diversified and includes coal, nuclear, gas, oil, and renewables. 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, Pennsylvania, Rhode Island, West Virginia and Wisconsin. As discussed in Properties, we have plans to add additional generation capacity to satisfy future growth in our utility service area. In our merchant generation business, we are adding generation capacity through several new renewable energy projects and uprates.

Dominion Generation’s earnings primarily result from the sale of electricity generated by our utility and merchant assets, as well as associated capacity from our merchant generation assets. Due to 1999 Virginia deregulation legislation, as amended in 2004 and 2007, revenues for serving Virginia jurisdictional retail load were based on capped rates through 2008. Additionally, fuel costs for the utility fleet, including purchased power, were subject to fixed-rate recovery provisions until July 1, 2007. Pursuant to

the 2007 amendments to the fuel cost recovery statute, annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, were re-instituted beginning July 1, 2007 for our Virginia jurisdictional customers. As discussed in Status of Electric Regulation in Virginia under Regulation, the Virginia General Assembly enacted legislation in April 2007 that returned the Virginia jurisdiction of our utility generation operations to a modified cost-of-service rate model, subject to base rate caps in effect through December 31, 2008. As a result, we reapplied the provisions of SFAS No. 71 to those operations on April 4, 2007, the date the legislation was enacted. We currently anticipate that the 2009 base rate review will result in an increase in rates, however, we cannot predict the outcome of future rate actions at this time. Variability in earnings for our utility operations results from changes in rates, the demand for services, which is primarily weather dependent, and labor and benefit costs, as well as the timing, duration and costs of scheduled and unscheduled outages.

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

COMPETITION

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

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

Dominion Generation’s other merchant assets also operate within functioning RTOs. Competitors include other generating assets bidding to operate within the RTOs. These RTOs have clearly identified market rules that ensure the competitive wholesale market is functioning properly. Dominion Generation’s merchant units have a variety of short and medium-term contracts, and also compete in the spot market with other generators to sell a variety of products including energy, capacity and ancillary services. It is difficult to compare various types of generation

given the wide range of fuels, fuel procurement strategies, efficiencies and operating characteristics of the fleet within any given RTO. However, 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.

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

In June 2008, we commenced the operation of two additional natural gas-fired electric generating units (Units 3 and 4) totaling 321 Mw at our Ladysmith power station (Ladysmith) to supply electricity during periods of peak demand. Construction has commenced on a fifth combustion turbine (Unit 5) which is expected to begin operations in mid-2009.

In July 2007, we filed an application with the Virginia Commission requesting approval to construct and operate a 585 Mw (nominal) carbon capture-compatible, clean-coal powered electric generation facility (Virginia City Hybrid Energy Center) to be located in Wise County, Virginia. The Virginia Commission issued a final order in March 2008 (Final Order), approving a certificate to construct and operate the proposed Virginia City Hybrid Energy Center, granting approval for us to continue to accrue AFUDC until capped rates end and approving a rate adjustment clause, allowing us current recovery of financing costs beginning January 1, 2009, as specified in the Final Order. In its Final Order, the Virginia Commission approved an initial return on common equity for the facility of 12.12%, consisting of a base return of 11.12% plus a 100 basis point premium that Virginia law provides for new conventional coal generation facilities. The Virginia Commission also authorized us to apply for an additional 100 basis point premium upon a demonstration that the plant is carbon-capture compatible. The enhanced return will apply to the Virginia City Hybrid Energy Center during construction and through the first twelve years of the facility’s service life. In July 2008, the Southern Environmental Law Center (SELC), on behalf of four environmental groups, filed a Petition for Appeal of the Final Order with the Supreme Court of Virginia. A decision is expected in April 2009.

An application for a permit to construct and operate the Virginia City Hybrid Energy Center, in compliance with federal and state air pollution laws, was filed in July 2006 with the Virginia Department of Environmental Quality and an application for another air permit for hazardous emissions was filed in February 2008. In June 2008, the Virginia Air Pollution Control Board (the Air Board), which assumed consideration of the applications, approved and issued both permits. The Air Board approved lower emissions limits than had been requested, including limits for sulfur dioxide (SO₂) and mercury. The Air Board also adopted our proposal to convert our Bremo power station from coal to natural gas within two years of the Virginia City Hybrid Energy Center going into service. The Bremo conversion project is part of our overall effort to reduce air emissions and is contingent upon the Virginia City Hybrid Energy Center entering service and Bremo receiving all necessary approvals, including approval from the Virginia Commission. See Environmental Strategy for more information. Construction of the Virginia City Hybrid Energy Center has commenced and the facility is expected to be in operation by 2012 at an estimated cost of approximately $1.8 billion, excluding financing costs. In August 2008, the SELC, on behalf of four environmental groups, filed Petitions for Appeal in Richmond Circuit Court challenging the approval of both of the air permits.

We are considering the construction of a third nuclear unit at a site located at North Anna power station (North Anna), which we own along with Old Dominion Electric Cooperative (ODEC). In November 2007, the NRC issued an Early Site Permit (ESP) to our subsidiary, Dominion Nuclear North Anna, LLC (DNNA). Also in November 2007, we, along with ODEC, filed an application with the NRC for a Combined Construction Permit and Operating License (COL) that references a specific reactor design and which would allow us to build and operate a new nuclear unit at North Anna. In January 2008, the NRC accepted our application for the COL and deemed it complete. In December 2008, we terminated a long-lead agreement with our vendor with respect to the reactor design identified in our COL application and certain related equipment. We intend to conduct a competitive process in 2009 to determine if vendors can provide an advanced technology reactor that could be licensed and built under terms acceptable to us. If, as a result of this process, we choose a different reactor design, we will amend our COL application, as necessary. We have not yet committed to building a new nuclear unit.

The NRC is required to conduct a hearing in all COL proceedings. In August 2008, the Atomic Safety and Licensing Board of the NRC granted a request for a hearing on one of eight contentions filed by the Blue Ridge Environmental Defense League. The mandatory NRC hearing will be uncontested with respect to other issues. We have a cooperative agreement with the DOE to share equally the cost of developing the COL. In April 2008, we and DNNA filed applications with the Virginia Commission and the North Carolina Commission, seeking approval to merge DNNA into Virginia Power. The Virginia and North Carolina applications were approved in July and September 2008, respectively, and DNNA was merged into Virginia Power effective December 1, 2008. Also in April 2008, we filed an application with the NRC to transfer the ESP from DNNA to Virginia Power and ODEC. This application was approved in October

2008 and the ESP has been transferred to Virginia Power and ODEC.

In June 2008, the DOE issued a solicitation announcement inviting the submission of applications for loan guarantees from the DOE under its Loan Guarantee Program in support of debt financing for nuclear power facility projects in the U.S. (the Solicitation). The Solicitation is specifically designed to provide loan guarantees to support those projects that employ new or significantly improved nuclear power facility technologies. Any loan guarantee which may be issued by the DOE pursuant to the Solicitation would be backed by the full faith and credit of the U.S. government, and would provide credit enhancement for all or a portion of the debt financing an applicant would incur with respect to such a project. In August 2008, we submitted to the DOE Part I of the application, including a high-level description of the proposed nuclear unit, project eligibility, financing strategy and progress to date related to critical path schedules. In December 2008, we submitted to the DOE Part II of the application. DOE is in the process of evaluating our application along with all other substantially completed applications submitted.

In March 2008, we purchased a power station development project in Buckingham County, Virginia (Bear Garden) that, once constructed, will generate about 590 Mw. The project already has air and water permits for a combined-cycle, natural gas-fired power station; however, such permits may need to be modified. In addition, construction of the project is subject to approval by the Virginia Commission, including approval under state regulations relating to bidding for the purchase of electric capacity and energy from other power suppliers, and the receipt of other environmental permits. A gas pipeline will also need to be constructed to provide gas supply to the power station. In March 2008, we filed an application with the Virginia Commission for authority to build the proposed combined-cycle, natural gas-fired power station and transmission interconnection line for an estimated $619 million, excluding financing costs. Pending the receipt of regulatory approval, we expect operations to begin in the summer of 2011.

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

In addition to the Powering Virginia projects, we have invested in several wind farm projects. 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 (NedPower). NedPower consists of two phases totaling 264 Mw. The first (164 Mw) and second (100 Mw) phases began commercial operations in July and December 2008, respectively.

In January 2008, we acquired a 50% interest in a joint venture with BP Alternative Energy Inc. (BP) to develop a wind-turbine facility in Benton County, Indiana (Fowler Ridge). Fowler Ridge is expected to be built in two phases and generate a total of 650 Mw. The first phase will total 300 Mw and is expected to reach full commercial operations in early 2009. We have a long-term agreement with the joint venture to purchase 200 Mw of energy, capacity and environmental attributes from

this first phase. We are currently in discussions with BP regarding development of the final 350 Mw phase. BP has developed an additional 100 Mw facility in which Dominion does not have an ownership interest.

In April 2008, we announced plans to develop a 300 Mw wind-turbine facility in central Illinois (Prairie Fork). Construction of this facility is subject to receipt of all necessary permits and approvals.

In January 2009, we announced a joint effort with BP to evaluate wind energy projects in Tazewell County and Wise County, Virginia, which, if completed, would increase the renewable energy capacity of our utility generation fleet.

Also, in January 2009, we successfully implemented an NRC-approved 7% uprate at Unit 3 of our Millstone power station. This increased the unit’s output by approximately 77 Mw from 1,150 Mw to 1,227 Mw, or enough to power an additional 60,000 homes.

SOURCES OF ENERGY SUPPLY

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

Nuclear Fuel—Dominion Generation primarily utilizes long-term contracts to support its nuclear fuel requirements. Worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices which are dependent on the market environment. Current agreements, inventories and spot market availability are expected to support current and planned fuel supply needs. Additional fuel is purchased as required to ensure optimal cost and inventory levels.

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

Dominion Generation’s natural gas and oil supply is obtained from various sources including: purchases from major and independent producers in the Mid-Continent and Gulf Coast regions; purchases from local producers in the Appalachian area; purchases from gas marketers; and withdrawals from underground storage fields owned by Dominion or third parties.

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

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

SEASONALITY

Sales of electricity for Dominion Generation typically vary seasonally as a result of the impact of changes in temperature and the availability of alternative sources for heating on demand by residential and commercial customers. Generally, the demand for electricity peaks during the summer and winter months to meet cooling and heating needs. In addition, an increase in heating degree-days for our utility operations does not produce the same

increase in revenue as an increase in cooling degree-days, due to seasonal pricing differentials and because alternative heating sources are more readily available.

NUCLEAR DECOMMISSIONING

Dominion Generation has a total of seven licensed, operating nuclear reactors at Surry power station (Surry) and North Anna in Virginia, Millstone power station (Millstone) in Connecticut and Kewaunee power station (Kewaunee) in Wisconsin.

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

We have decommissioning obligations for each of these power stations as discussed in Note 15 to our Consolidated Financial Statements. Decommissioning involves the decontamination and removal of radioactive contaminants from a nuclear power station once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers and placed into trusts have been invested to fund the expected future costs of decommissioning the Surry and North Anna units. As part of our acquisition of both Millstone and Kewaunee, we acquired decommissioning funds for the related units.

While the current economic downturn has resulted in a decrease in the value of investments held by our nuclear decommissioning trusts, 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. We also believe that the decommissioning funds for the Surry and North Anna units will be sufficient, particularly when combined with ratepayer collections and contributions to these decommissioning trusts, if such future collections and contributions are required. We will continue to monitor our nuclear decommissioning trusts to ensure they meet the minimum financial assurance requirement, which may include the use of parent company guarantees, surety bonding or other financial guarantees recognized by the NRC.

The total estimated cost to decommission our eight nuclear units is $4.5 billion in 2008 dollars and is primarily based upon site-specific studies completed in 2006. For all units except Millstone Units 1 and 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. In August 2008, we filed an application with the NRC to renew the Kewaunee operating license. A renewal would permit Kewaunee to operate through December 21, 2033. The NRC docketed the application in October 2008. No requests for a hearing were received on the application, although there will be opportunities for public input as the NRC conducts its review of the application. The NRC’s schedule contemplates completion of the uncontested proceeding in November 2010. The license expiration dates for our units are shown in the following table.

Corporate and Other

We also have a Corporate and Other segment that includes our corporate, service company and other functions (including unallocated debt), corporate-wide commodity risk management, the remaining assets of DCI, and the net impact of certain operations disposed of and the results of certain operations to be disposed of, which are discussed in Note 5 to our Consolidated Financial Statements. Operations disposed of during 2008 included certain DCI operations. Operations disposed of during 2007 included all of our non-Appalachian E&P operations, three natural gas-fired merchant generation peaker facilities and certain DCI operations. Operations to be disposed of include Peoples and Hope, which we agreed to sell to BBIFNA in July 2008. In addition, Corporate and Other includes specific items attributable to our operating segments that are not included in profit measures evaluated by executive management in assessing the segments’ performance or allocating resources among the segments.

ENVIRONMENTAL STRATEGY

We are committed to being a good environmental steward. Our ongoing objective is to provide reliable, affordable energy for our customers while being environmentally responsible. Our integrated strategy to meet this objective consists of four major elements:

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

We are working to improve our own energy efficiency, both in using less fuel to produce the same amount of energy and to use less energy in our operations. Recent uprates of our facilities have resulted in significant increases in generation capacity and a lower emitting fleet to meet the needs of our customers.

Renewable energy is also an important component of a diverse and reliable energy mix. Both Virginia and North Carolina have passed legislation setting targets for renewable power. We are committed to meeting Virginia’s goal of 12% renewable power by 2022 and North Carolina’s renewable portfolio standard of 12.5% by 2021.

We are actively assessing development opportunities in our service territories for renewable technologies. In November 2007, we issued a request for proposals (RFP) for renewable energy projects in Virginia, North Carolina or elsewhere in the PJM Interconnect region. The RFP seeks the purchase of renewable energy generation projects, as well as renewable energy credits. Our regulated utility currently provides approximately two percent of its generation from renewable sources. We also anticipate using at least 10% biomass (woodwaste) at the Virginia City Hybrid Energy Center.

In addition, Dominion is a 50% owner of the NedPower wind energy facility in Grant County, West Virginia. Our share of this project produces 132 Mw of renewable energy. Dominion has also acquired a 50% interest in a joint venture with BP to develop the Fowler Ridge wind-turbine facility in Benton County, Indiana. The facility is expected to be built in two phases and generate a total of 650 Mw. The first phase will total 300 Mw and is expected to reach full commercial operations in early 2009. We have a long-term agreement with the joint venture to purchase 200 Mw of energy, capacity and environmental attributes from this first phase. We are currently in discussions with BP regarding development of the final 350 Mw phase. BP has developed an additional 100 Mw facility in which Dominion does not have an ownership interest.

We have announced a comprehensive generation growth program, referred to as Powering Virginia, which involves the development, financing, construction and operation of new multi-fuel, multi-technology generation capacity to meet the growing demand in our core market of Virginia. We expect that these investments collectively will provide the following benefits: expanded electricity production capability; increased technological and fuel diversity; and a reduction in the carbon dioxide (CO₂) emission intensity of our generation fleet. A critical aspect of the Powering Virginia program is the extent to which we seek to reduce the carbon intensity of our generation fleet by developing generation facilities with zero CO₂ and low CO₂ emissions, as well as economically viable facilities that can be equipped for CO₂ capture and storage. There is no current economically viable technological solution to retro-fit existing fossil-fueled technology to capture and store greenhouse gas (GHG) emissions. Given that new generation units have useful lives of up to 55 years, we will give full consideration to CO₂ and other GHG emissions when making long-term decisions. See Dominion Generation–Properties for more information.

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

Conservation and Load Management Programs

We have conducted a series of short-term pilot programs focused on energy conservation and demand response. The pilots were offered to a selection of 4,550 customers in our electric utility’s central, eastern and northern Virginia service areas. To help ensure that the results were representative, solicitations were given to select customers. No customer could participate in more than one pilot. We reported results from the pilots at least quarterly to the Virginia Commission staff to help evaluate their effectiveness. Most of these pilots had ended as of December 31, 2008.

The pilots approved by the Virginia Commission included:

In June 2008, we announced an energy conservation and load management plan that, if implemented, is expected to produce long-term environmental benefits while providing our electric utility customers with cost savings. The plan is part of our Powering Virginia strategy to meet the future needs of customers. We expect to launch the plan in early 2010, subject to approval by the Virginia Commission and the North Carolina Commission, as applicable.

A key component of the plan is the potential installation of “smart grid” technologies that are designed to enhance our electric distribution system by allowing energy to be delivered more efficiently. Dependent upon the outcome of demonstration projects taking place in 2009, we expect to make a significant investment in replacing all of our existing meters with Advanced Metering Infrastructure. The technology is expected to lead to improvements in service reliability and the ability of customers to monitor and control their energy use. Additionally, programs in the conservation plan include:

REGULATION

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

State Regulations

ELECTRIC

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

Status of Electric Regulation in Virginia

2007 Virginia Regulation Act and Fuel Factor Amendments

On July 1, 2007, legislation amending the Virginia Electric Utility Restructuring Act (the Regulation Act) and the fuel factor statute became effective, which significantly changed electricity regulation in Virginia. Prior to the Regulation Act, our base rates in Virginia were to be capped at 1999 levels until December 31, 2010, at which time Virginia was to convert to retail competition for its electric supply service. The Regulation Act ended capped rates two years early, on December 31, 2008, at which time retail competition would be available only to individual retail customers with a demand of more than 5 Mw and non-residential retail customers who obtain Virginia Commission approval to aggregate their load to reach the 5 Mw threshold. Individual retail customers will also be permitted to purchase renewable energy from competitive suppliers if their incumbent electric utility does not offer a 100% renewable energy tariff.

Pursuant to the Regulation Act, the Virginia Commission entered an order in January 2009 initiating reviews of the base rates and terms and conditions of all investor-owned utilities in Virginia. The Company must submit its filing and accompanying schedules on or before April 1, 2009, and it anticipates that its filing will support an increase in base rates. The ROE in that rate review will be no lower than that reported by not less than a majority of comparable utilities within the southeastern U.S., with certain limitations, as described in the Act. Possible outcomes of the 2009 rate review, according to the Regulation Act, include a rate increase, a rate decrease, and a refund of earnings more than 50 basis points above the authorized ROE. We are unable to predict the outcome of future rate actions at this time. However, an unfavorable outcome could adversely affect our results of operations, financial condition and cash flows.

After the 2009 rate review, the Virginia Commission will conduct biennial reviews of our rates, terms and conditions beginning in 2011. As in the 2009 rate review, our ROE in the biennial reviews can be no lower than that reported by not less than a majority of comparable utilities within the southeastern U.S., with certain limitations, as described in the Act. The Commission shall be authorized to increase our base rates if our earnings are more than 50 basis points below the authorized level. If our earnings are more than 50 basis points above the authorized level, such earnings will be shared with customers. If over-earning persists for two consecutive biennial periods, in addition to earnings sharing, rates may also be reduced.

Separate from base rates, the Regulation Act also authorizes stand-alone rate adjustment clauses for recovery of costs for new generation projects, environmental compliance, FERC-approved transmission costs, conservation and energy efficiency programs, and renewables programs. The Act also provided for enhanced returns on capital expenditures on specific new generation projects, including but not limited to nuclear generation, clean coal/carbon capture compatible generation, and renewable generation projects.

The Regulation Act also continues statutory provisions directing us to file annual fuel cost recovery cases with the Virginia Commission beginning in 2007 and continuing thereafter, as discussed in Virginia Fuel Expenses.

Virginia Fuel Expenses

Under amendments to the Virginia fuel cost recovery statute passed in 2004, our fuel factor provisions were frozen until July 1, 2007. Fuel prices increased considerably during that period, which resulted in our fuel expenses being significantly in excess of our fuel cost recovery. Pursuant to the 2007 amendments to the fuel cost recovery statute, annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs, were re-instituted beginning July 1, 2007. While the 2007 amendments did not allow us to collect any unrecovered fuel expenses that were incurred prior to July 1, 2007, once our fuel factor was adjusted, this mechanism ensures dollar-for-dollar recovery for prudently incurred fuel costs.

In April 2007, we filed a Virginia fuel factor application with the Virginia Commission. The application showed a need for an annual increase in fuel expense recovery for the period July 1, 2007 through June 30, 2008 of approximately $662 million; however, the requested increase was limited to $219 million under the 2007 amendments to the fuel cost recovery statute, which limited the increase to an amount that resulted in the residential customer class not receiving an increase of more than 4% of total rates in effect as of June 30, 2007. The Virginia Commission approved a fuel factor increase for Virginia jurisdictional customers of approximately $219 million, effective July 1, 2007, with the balance of approximately $443 million deferred for subsequent recovery subject to Virginia Commission approval, without interest, during the period commencing July 1, 2008 and ending June 30, 2011.

In May 2008, we filed an application to revise our fuel factor with the Virginia Commission that would have resulted in an annual increase from 2.232 cents per kWh to 4.245 cents per kWh, effective July 1, 2008. This revised factor included $231 million of prior year under-recovered fuel expense out of a total

estimated prior year under-recovered balance of $697 million with the remaining deferred fuel balance expected to be recovered over the next two fuel rate years beginning July 1, 2009. As part of the application, we proposed adoption of a rule that would limit the fuel factor to 3.893 cents per kWh for the current fuel period of July 1, 2008 through June 30, 2009. In order to achieve this lower fuel factor increase, the proposal would have delayed recovery of the prior year under-recovered fuel balance of $697 million to be collected over a three-year period beginning July 1, 2009.

The Virginia Commission approved a settlement proposed by us and other parties, which provided for the following effective July 1, 2008:

The resulting increase in a 1,000 kWh Virginia jurisdictional residential customer’s monthly bill is approximately 18% for the 2008 through 2009 fuel period.

North Carolina Regulation

In 2004, the North Carolina Commission commenced a review of our North Carolina base rates and subsequently ordered us to file a general rate case to show cause why our North Carolina jurisdictional base rates should not be reduced. The rate case was filed in September 2004, and in March 2005 the North Carolina Commission approved a settlement that included a prospective $12 million annual reduction in current base rates and a five-year base rate moratorium, effective as of April 2005. Fuel rates are still subject to annual fuel rate adjustments, with deferred fuel accounting for over- or under-recoveries of fuel costs.

In September 2008, our electric utility subsidiary filed an application to revise our fuel factor with the North Carolina Commission, requesting an annual increase in our North Carolina fuel factor from 2.221 cents per kWh to 3.825 cents per kWh to be effective January 1, 2009. The proposal would result in an annual increase in fuel revenue of approximately $69 million for the North Carolina jurisdiction. In December 2008, our electric utility subsidiary, the Public Staff of the North Carolina Commission and other parties filed a proposed settlement that would increase our North Carolina fuel factor from 2.221 cents per kWh to 3.206 cents per kWh. The North Carolina Commission approved the settlement in December 2008. The resulting increase in annual fuel revenue is approximately $42 million for the North Carolina jurisdiction.

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 or commercial natural gas consumers. However, in cooperation with the Ohio Commission, we have offered retail choice to residential and commercial customers. At December 31, 2008, approximately 849,500 of our 1.2 million Ohio customers were participating in this Energy Choice program. In October 2006, Dominion East Ohio implemented a pilot program approved by the Ohio Commission as a transitional step towards the improvement and expansion of the Energy Choice program. Under the pilot program, Dominion East Ohio entered into gas purchase contracts with selected suppliers at a fixed price above the New York Mercantile Exchange (NYMEX) month-end settlement. This Standard Service Offer (SSO) pricing mechanism replaced 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.

In June 2008, the Ohio Commission approved a settlement filed in response to Dominion East Ohio’s application seeking approval of Phase 2 of its plan to restructure its commodity service. Under that settlement, the existing SSO program was continued through March 2009 with an update to the fixed rate adder to the NYMEX price. Starting in April 2009, Dominion East Ohio will still buy natural gas under the SSO program for customers not eligible to participate in the Energy Choice program, but will place Energy Choice-eligible customers in a direct retail relationship with selected suppliers, which will be designated on the customers’ bills. Subject to ultimate 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. Large industrial customers in Ohio also source their own natural gas supplies.

Pennsylvania—In Pennsylvania, supplier choice is available for all residential and small commercial customers of Peoples. At December 31, 2008, approximately 108,000 of our 359,000 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 the retail natural gas markets served by Hope. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.

Rates

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 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.

In August 2007, Dominion East Ohio filed an application to increase base rates. In this rate case, Dominion East Ohio requested approval of an increase in operating revenues of approximately $73 million and proposed an increase in demand-side management spending. Subsequently, Dominion East Ohio also requested that the Ohio Commission consolidate its review of the rate case application with Dominion East Ohio’s application, filed in February 2008, for approval to recover costs related to a 25-year program to replace 19% of its 21,000-mile pipeline system, which is expected to cost approximately $2.6 billion. In August 2008, Dominion East Ohio reached an agreement with intervening parties on all issues in the base rate case except for one related to rate design (Settlement Agreement).

In October 2008, the Ohio Commission issued its Opinion and Order in this case, in which the Ohio Commission approved the majority of the Settlement Agreement, but modified the allowed return on rate base from the 8.49% agreed upon in the Settlement Agreement to 8.29%. The resulting annual revenue increase approved by the Ohio Commission was approximately $37.5 million, which was reflected in base rates commencing October 16, 2008. The Ohio Commission also approved the SFV rate design supported by Ohio Commission staff and Dominion East Ohio for certain rate schedules, as well as the other terms of the Settlement Agreement, including a cost recovery mechanism for the implementation of automated meter reading equipment and a cost recovery mechanism for an initial five-year period of the pipeline replacement program. Under the SFV rate design, Dominion East Ohio will recover a larger portion of its fixed operating costs through a flat monthly charge accompanied by a lower volumetric base delivery rate. In addition, the Settlement Agreement requires Dominion East Ohio to increase its annual spending for energy conservation programs to a total of $9.5 million and to make grants totaling $1.2 million to several organizations to provide payment assistance and energy efficiency education to low-income customers. The Ohio Commission also ordered Dominion East Ohio to work in consultation with Commission staff and other parties to the case to develop a low-income pilot program under which a total of 5,000 eligible low-income, low-usage customers would receive a $4.00 reduction in their monthly service charge, as a result of implementing the new rate design.

In December 2008, the Ohio Commission granted Dominion East Ohio’s request for rehearing in the base rate case and approved the 8.49% allowed rate of return on rate base that had been agreed upon previously by all parties to the case. The result-

ing $3 million annual revenue increase, which was incremental to the $37.5 million increase approved in October 2008, was reflected in revised rates commencing December 22, 2008.

The West Virginia Commission issued an order in March 2008, approving a settlement of Hope’s 2005 and 2006 gas cost recovery proceedings, approving the withdrawal of the joint application for approval of the sale of Hope to Equitable, and dismissing the claims of a former employee against Hope. In this order, the West Virginia Commission concluded that no adjustments to Hope’s gas cost rates are warranted based on allegations raised by the former employee. Accordingly, the gas cost rates effective November 1, 2007 and April 1, 2008 approved by the March 2008 order have been upheld by the West Virginia Commission.

In October 2008, Hope filed a request with the West Virginia Commission for an increase in the base rates it charges for natural gas service. The requested new base rates would increase Hope’s revenues by $34.4 million annually.

Federal Regulations

EPACT AND THE REPEAL OF PUHCA

EPACT was signed into law in August 2005. Among other things, EPACT repealed the Public Utilities Holding Company Act (PUHCA) of 1935, effective February 2006. PUHCA regulated many significant aspects of a registered holding company system, such as Dominion’s. As a result of PUHCA’s repeal, utility holding companies, including Dominion’s system, are no longer limited to a single integrated public utility system. Further, utility holding companies are no longer restricted from acquiring businesses that may not be related to the utility business. Jurisdiction over certain holding company related activities has been transferred to the FERC, including the issuances of securities by public utilities, the acquisition of securities of utilities, the acquisition or sale of certain utility assets, and mergers with another electric utility or holding company. In addition, both FERC and state regulators are permitted to review the books and records of any company within a holding company system.

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

FEDERAL ENERGY REGULATORY COMMISSION

Electric

Under the Federal Power Act, FERC regulates wholesale sales and transmission of electricity in interstate commerce by public utilities. Our electric utility subsidiary sells electricity in the PJM wholesale market and our merchant generators sell electricity in the PJM, Midwest ISO and ISO New England wholesale markets 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. In May 2005, FERC issued an order finding that PJM’s existing transmission service rate design may not be just and reasonable, and ordered an investigation and hearings on the matter. In January 2008, FERC affirmed its earlier decision that the PJM transmission rate design for existing facilities had not become unjust and unreasonable. For recovery of costs of investments of new PJM-planned transmission facilities that operate at or above 500 kV, FERC established a regional rate design where all customers pay a uniform rate based on the costs of such investment. For recovery of costs of investment in new PJM-planned transmission facilities that operate below 500 kV, FERC affirmed its earlier decision to allocate costs on a beneficiary pays approach. A notice of appeal of this decision was filed in February 2008 at the United States Court of Appeals for the Seventh Circuit and the appeal is pending. We cannot predict the outcome of the appeal.

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

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

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 NERC as the ERO beginning on January 1, 2007. In late 2006, FERC also issued an initial order approving many reliability standards that went into effect on January 1, 2007. Beginning in June 2007, entities that violate standards will be subject to fines of between $1 thousand and $1 million per day, and can also be assessed non-monetary penalties, depending upon the nature and severity of the violation.

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 the expenditures to be significant.

In April 2008, FERC granted an application by our electric transmission operations to establish a forward-looking formula rate mechanism that will update transmission rates on an annual basis and approved an ROE of 11.4% on the common equity base of these operations, effective as of January 1, 2008. The formula rate is designed to cover the expected cost of service for

each calendar year and will be trued up based on actual costs. While other transmission owners in the PJM region use a formula rate based on historic costs, our formula rate is based on projected costs. The FERC ruling did not materially impact our results of operations; however, going forward the FERC-approved formula method will allow us to earn a more current return on our growing investment in electric transmission infrastructure.

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

In May 2008, the Maryland Public Service Commission, Delaware Public Service Commission, Pennsylvania Commission, New Jersey Board of Public Utilities, the American Forest & Paper Association, the Portland Cement Association and several other organizations representing consumers in the PJM region (the RPM Buyers) filed a complaint at FERC claiming that PJM’s Reliability Pricing Model’s transitional auctions have produced unjust and unreasonable capacity prices. The RPM Buyers requested that a refund effective date of June 1, 2008 be established and that FERC provide appropriate relief from unjust and unreasonable capacity charges within 15 months. In September 2008, FERC dismissed the complaint. The RPM Buyers requested rehearing of the FERC order in October 2008 and rehearing is pending. We cannot predict the outcome of the rehearing.

In September 2008, we filed a Deferral Recovery Charge (DRC) request with FERC to recover approximately $153 million of RTO costs that we have been unable to recover due to a statutory rate cap established under Virginia law. The RTO costs include:

In December 2008, FERC approved the DRC to become effective January 1, 2009, as requested. However, recovery of RTO costs through the DRC will not commence until the date established by the Virginia Commission that permits us to implement such recovery. In January 2009, requests for rehearing of the DRC by FERC were filed by the Virginia Commission and the Virginia Attorney General’s office. We cannot predict the outcome of the rehearing.

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 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 transmission and storage activities are generally 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 transmission rates and reduced fuel retention levels for storage service customers. As part of the settlement, DTI and all signatory parties agreed to a rate moratorium until 2010.

In December 2007, DTI and the Independent Oil and Gas Association of West Virginia, Inc. reached a settlement agreement on DTI’s gathering and processing rates for the period January 1, 2009 through December 31, 2011. This settlement maintains the gas retainage fee structure that DTI has utilized since 2001.

In connection with the settlement, DTI also agreed to invest at least $20 million annually in Appalachian gathering-related assets. The new rates have been approved by FERC as negotiated rates.

Environmental Regulations

GENERAL

Each of our operating segments faces substantial laws, regulations and compliance costs with respect to environmental matters. In addition to imposing continuing compliance obligations, these laws and regulations authorize the imposition of substantial penalties for noncompliance, including fines, injunctive relief and other sanctions. If our expenditures for pollution control technologies and associated operating costs are not recoverable from customers through regulated rates (in regulated jurisdictions) or market prices (in deregulated jurisdictions), those costs could adversely affect future results of operations and cash flows. The cost of complying with applicable environmental laws, regulations and rules is expected to be material to the Company. We have applied for or obtained the necessary environmental permits for the operation of our facilities. Many of these permits are subject to reissuance and continuing review. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, 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.

AIR

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.

In March 2005, the EPA Administrator signed both the Clean Air Interstate Rule (CAIR) and the Clean Air Mercury Rule (CAMR). These rules, if implemented, would require significant reductions in SO₂, nitrogen oxide (NO_X) and mercury emissions from electric generating facilities.

In February 2008, the D.C. Appeals Court issued a ruling that vacates CAMR as promulgated by the EPA. In May 2008, the EPA’s appeal of this decision with the D.C. Appeals Court was denied. In September 2008, the Utility Air Regulatory Group filed a petition requesting that the U.S. Supreme Court review the D.C. Appeals Court decision to vacate the EPA rule. In October 2008, the Solicitor General, on behalf of the EPA, also filed a petition with the U.S. Supreme Court, however in February 2009, it filed a motion to dismiss its petition. Also in February 2009 the U.S. Supreme Court denied the Utility Air Regulatory Group’s petition. The EPA Administration has announced that the EPA will proceed with a Maximum Achievable Control Technology rule-making. It should be noted that we continue to be governed by individual state mercury emission reduction regulations in Massachusetts and Illinois that were largely unaffected by the CAMR ruling. We cannot predict how the EPA or the states may alter their approach to reducing mercury emissions.

In July 2008, the D.C. Appeals Court issued a ruling vacating CAIR as promulgated by the EPA. A number of parties, including the EPA, filed petitions for a rehearing of the decision. The Court’s decision resulted in a decline in the market value of SO₂ allowances that could have limited our ability to monetize the value of these allowances in the future. During the third quarter of 2008, we tested our SO₂ allowances for impairment and concluded that no impairment adjustment was required as a result of this decline in market value. In December 2008, the Court denied rehearing, but also issued a decision to remand CAIR to the EPA, so the CAIR rules remain in effect. The remand resulted in an increase in the market value of SO₂ allowances and allows CAIR to remain in place until such time that the EPA develops and implements a new rulemaking addressing the issues identified by the Court. We cannot predict how a new rulemaking will impact future SO₂ and NO_X emission reduction requirements beyond CAIR.

In June 2005, the EPA finalized amendments to the Regional Haze Rule, also known as the Clean Air Visibility Rule (CAVR). Although we anticipate that the emission reductions achieved through compliance with other CAA required programs will generally address CAVR if those rules proceed, additional emission reduction requirements may be imposed on our facilities.

Implementation of projects to comply with SO₂, NO_X and mercury limitations, and other state emission control programs are ongoing and will be influenced by changes in the regulatory

environment, availability of emission allowances and emission control technology. In response to the federal CAA and state regulatory requirements, we estimate that we will make capital expenditures at our affected generating facilities of approximately $700 million during the period 2009 through 2013.

WATER

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. In July 2004, the EPA published regulations under CWA Section 316b that govern existing utilities that employ a cooling water intake structure and that have flow levels exceeding a minimum threshold. The EPA’s rule presented several compliance options. However, in January 2007, the U.S. Court of Appeals for the Second Circuit issued a decision on an appeal of the regulations, remanding the rule to the EPA. In July 2007, the EPA suspended the regulations pending further rulemaking, consistent with the decision issued by the U.S. Court of Appeals for the Second Circuit. In November 2007, a number of industries appealed the lower court decision to the U.S. Supreme Court. In April 2008, the U.S. Supreme Court granted the industry request to review the question of whether Section 316b of the CWA authorizes the EPA to compare costs with benefits in determining the best technology available for minimizing “adverse environmental impact” at cooling water intake structures. Oral arguments were presented before the U.S. Supreme Court in December 2008 with a decision expected in 2009. We have sixteen facilities that are likely to be subject to these regulations. We cannot predict the outcome of the judicial or EPA regulatory processes, nor can we determine with any certainty what specific controls may be required.

In August 2006, the Connecticut Department of Environmental Protection (CTDEP) issued a notice of a Tentative Determination to renew our Millstone power station’s National Pollutant Discharge Elimination System (NPDES) permit, which included a draft copy of the revised permit. In October 2007, CTDEP issued a report to the hearing officer for the tentative determination stating the agency’s intent to further revise the draft permit. In December 2007, the CTDEP issued a new draft permit. An administrative hearing on the draft permit began in January 2009, with a Final Determination expected to be issued by the CTDEP later in 2009. Until the final permit is reissued, it is not possible to predict any financial impact that may result.

In October 2003, the EPA and the Massachusetts Department of Environmental Protection (MADEP) each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Following various appeals, in December 2007, the EPA issued an administrative order to Brayton Point that contained a schedule for implementing the permit. On the same day, Brayton Point withdrew its appeal of the permit from the U.S. Court of Appeals. In March 2008, MADEP issued a companion order resolving the state appeal and implementing the state permit. The state appeal was dismissed the same day. Currently, we estimate the total cost to install these cooling towers at approximately $620 million, which is included in our planned capital expenditures through 2013.

MANUFACTURED GAS SITES

We have determined that we are associated with 21 former manufactured gas plant sites. Studies conducted by other utilities at their former manufactured gas plants have indicated that their sites contain coal tar and other potentially harmful materials. None of the 21 former sites with which we are associated is under investigation by any state or federal environmental agency. For more information on these sites see Note 23 to our Consolidated Financial Statements.

SOLID AND HAZARDOUS WASTE

The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), provides for an immediate response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances into the environment and authorizes the U.S. government either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of waste at certain sites. These potentially responsible parties (PRPs) can be ordered to perform a cleanup, be sued for costs associated with an EPA-directed cleanup, voluntarily settle with the U.S. Government concerning their liability for cleanup costs, or voluntarily begin a site investigation and site remediation under state oversight.

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

GLOBAL CLIMATE CHANGE

General

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

For Dominion Generation, our direct CO₂ emissions, based on ownership, were approximately 56 million metric tonnes in 2007. For 2007, DTI’s direct CO₂ equivalent emissions were approximately 2.3 million metric tonnes, Dominion East Ohio’s direct CO₂ equivalent emissions were approximately 1.4 million metric tonnes and Dominion E&P’s direct CO₂ equivalent emissions were approximately 0.4 million metric tonnes. While we do not have final 2008 emissions data for Dominion Generation, DTI, Dominion East Ohio or Dominion E&P, we do not expect a significant variance in emissions from 2007 amounts. With respect to electric generation, the emissions reported are for CO₂ directly emitted to the atmosphere based on the combustion of

carbon-based fuels. Direct CO₂ emissions are provided based on emissions from primary stack and emissions from any auxiliary combustion equipment located at the electric generation facility. Primary facility stack emissions of CO₂ from carbon based fuel combustion are directly measured via methods set forth under 40 CFR Part 75 of the United States Code (USC). For those emission sources not covered under 40 CFR Part 75 requirements, quantification is based on fuel combustion and emission factors consistent with industry best practices. For DTI, the protocol used to calculate the non-combustion related emissions reported above was Greenhouse Gas Emission Estimation Guidelines for Natural Gas Transmission and Storage, Volume 1 – GHG Estimation Methodologies and Procedures. Revision 2, September 28, 2005 developed by the Interstate Natural Gas Association of America. For Dominion East Ohio, the protocol used to calculate the non-combustion related emissions was the American Gas Association’s Draft Greenhouse Emissions Estimation Methodologies and Procedures for Natural Gas Distribution Operations. For Dominion E&P emissions, the protocol used was the American Petroleum Institute February 2004 Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Gas Industry.

Climate Change Legislation

The new presidential administration and the new Congress bring expanded support for federal legislative action and regulatory initiatives for mandatory GHG emissions reductions. The new presidential administration is expected to offer comprehensive legislation to establish an economy-wide program to significantly reduce GHG emissions. Other legislative efforts may propose reduction requirements measured against current emission levels. These proposals will possibly include some emission allowances allocated to major sectors of the economy covered by the legislation with a remaining amount of allowances auctioned to interested parties, both covered and non-covered sectors of the economy. Climate change legislation continues to evolve and accordingly, we cannot predict what, if any, legislation will ultimately pass.

In April 2007, the U.S. Supreme Court ruled that the EPA has the authority to regulate GHG emissions, which could result in future EPA action. Possible outcomes from this decision include regulation of GHG emissions from various sources, including electric generation and gas transmission and distribution facilities.

Dominion currently supports the enactment of federal legislation that regulates GHG emissions economy-wide, establishes a system of tradable allowances, slows the growth of GHG emissions in the near term and reduces GHG emissions in the long term. In addition, Dominion supports legislation that sets a realistic baseline year and schedule and that is designed in a way to limit potential harm to the economy and competitive businesses.

In addition to possible federal action, some regions and states in which we operate have already or may adopt GHG emissions reduction programs. For example, the Virginia Energy Plan, released by the Governor of Virginia in September 2007, includes a goal of reducing GHG emissions statewide back to 2000 levels by 2025. The Governor formed a Commission on Climate Change to develop a plan to achieve this goal. In November 2008, the Commission on Climate Change formulated their recommendations to the Governor.

In July 2008, Massachusetts passed the Global Warming Solutions Act (the Act). Among other provisions, the Act sets

economy-wide GHG emissions reduction goals for Massachusetts, including reductions of 10% to 25% below 1990 levels by 2020, interim goals for 2030 and 2040, and reductions of 80% below 1990 levels by 2050. Regulations implementing the Act have not yet been proposed or implemented. We operate two coal/oil-fired generating power stations in Massachusetts that are subject to the implementation of the Act.

Additionally, Massachusetts, Rhode Island and Connecticut, among other states, have joined the Regional Greenhouse Gas Initiative (RGGI), a multi-state effort to reduce CO₂ emissions in the Northeast to be implemented through state specific regulations. Under the initiative, aggregate CO₂ emissions from power plants in participating states would be required to be stabilized at current levels from 2009 to 2015. Further, reductions from current levels would be required to be phased in starting in 2016 such that by 2019 there would be a 10% reduction in participating state power plant CO₂ emissions.

Two of our facilities, Brayton Point and Salem Harbor, are subject to existing regulations on CO₂ under Massachusetts Regulation 310 CMR 7.29. These facilities can comply with these regulations either through procurement of GHG emission credits or payment into the Massachusetts GHG Expendable Trust. In 2008, the combined CO₂ compliance obligation for these two power stations is for approximately 456,048 tons of CO₂. The state of Massachusetts has conditionally approved 212,400 tons of GHG emission credits for a Dominion GHG emission credit project.

Three of our facilities, Brayton Point, Salem Harbor and Manchester Street, are subject to RGGI. Beginning with calendar year 2009, RGGI requires that we cover each ton of CO₂ direct stack emissions from these facilities with either an allowance or an offset. The allowances can be purchased through auction or through a secondary market. We participated in allowance auctions in September and December of 2008 and have procured allowances to meet our estimated compliance requirements under RGGI for 2009. We do not expect these allowances to have a material impact on our results of operations or financial condition.

The U.S. is currently not a party to the Kyoto Protocol, which is a protocol to the United Nations Framework Convention on Climate Change and became effective for signatories on February 16, 2005. The Kyoto Protocol process generally requires developed countries to cap GHG emissions at certain levels during the 2008-2012 time period. At the conclusion of the December 2007 United Nations Climate Change Conference in Bali, Indonesia, the Bali Action Plan was adopted which identifies a timeline for the consideration of possible post-2012 international actions to further address climate change. The U.S. is expected to participate in this process.

The cost of compliance with future GHG emission reduction programs could be significant. Given the highly uncertain outcome and timing of future action by the U.S. federal government and states on this issue, we cannot predict the financial impact of future GHG emission reduction programs on our operations or our customers at this time.

Dominion’s Strategy for Voluntarily Reducing CO₂ Emissions

While Dominion has not established a stand alone CO₂ emissions reduction target or timetable, we are actively engaged in voluntary reduction efforts and will work toward achieving the standards

established by existing state regulations as set forth above. We have an integrated strategy for reducing CO₂ emission intensity that is based on maintaining a diverse fuel mix, including nuclear, coal, gas, hydro and renewable energy, investing in renewable energy projects, and promoting energy conservation and efficiency efforts. See Environmental Strategy above for a description of our strategy for reducing CO₂ emission intensity. Some recent efforts that have or are expected to reduce the Company’s carbon intensity include:

While, upon entering service, our new Virginia City Hybrid Energy Center which is currently under construction in Southwest Virginia will be a new source of GHG emissions, we have taken steps to minimize the impact on the environment. The new plant is expected to use at least ten percent biomass for fuel and was designed to be carbon-capture compatible, meaning that technology to capture CO₂ can be added to the station when it becomes commercially available. Also, we have announced plans to convert our coal units at Bremo power station to natural gas, contingent upon the Virginia City Hybrid Energy Center entering service and receipt of necessary approvals. See Dominion Generation—Properties for more information on the projects above, as well as other projects under current development.

Since 2000, we have tracked the emissions of our electric generation fleet. Our electric generation fleet employs a mix of fuel and renewable energy sources. Comparing annual year 2000 to annual year 2007, our electric generating fleet (based on our ownership percentage) reduced its average CO₂ emissions rate per megawatt-hour of energy produced from electric generation by about 15%. During such time period the capacity of our electric generation fleet has grown.

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, it 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 11 to our Consolidated Financial Statements.

SPENT NUCLEAR FUEL

Under provisions of the Nuclear Waste Policy Act of 1982, we have entered into contracts with the DOE for the disposal of spent nuclear fuel. The DOE failed to begin accepting the spent fuel on January 31, 1998, the date provided by the Nuclear Waste Policy Act and by our contracts with the DOE. In January 2004, we and certain of our direct and indirect subsidiaries filed lawsuits in the U.S. Court of Federal Claims against the DOE requesting damages in connection with its failure to commence accepting spent nuclear fuel. A trial occurred in May 2008 and post-trial briefing and argument concluded in July 2008. On October 15, 2008, the Court issued an opinion and order for us in the amount of approximately $155 million for our spent fuel-related costs through June 30, 2006, and judgment was entered by the Court on October 28, 2008. On December 24, 2008, the government appealed the judgment to the U. S. Court of Appeals for the Federal Circuit and the appeal was docketed on December 30, 2008. Briefing on the appeal is expected to take place in 2009. Payment of any damages will not occur until the appeal process has been resolved. We cannot predict the outcome of this matter; however, in the event that we recover damages, such recovery, including amounts attributable to joint owners, is not expected to have a material impact on our results of operations. We will continue to manage our spent fuel until it is accepted by the DOE.

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 results of operations can be affected by changes in the weather. Weather conditions directly influence the demand for electricity and natural gas, and affect the price of energy commodities. In addition, severe weather, including hurricanes and winter storms, can be destructive, causing outages and property damage that require us to incur additional expenses. Additionally, droughts can result in reduced water levels that could adversely affect operations at some of our power stations.

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, the revision or reinterpretation of existing laws or regulations, or penalties imposed for non-compliance with existing laws or regulations may require us to incur additional expenses.

We could be subject to penalties as a result of mandatory reliability standards. As a result of EPACT, owners and operators of bulk power transmission systems, including Dominion, are subject to mandatory reliability standards enacted by NERC and enforced by FERC. If we are found not to be in compliance with the mandatory reliability standards we could be subject to sanctions, including substantial monetary penalties.

Our costs of compliance with environmental laws are significant, and the cost of compliance with future environmental laws could adversely affect our cash flow and profitability. Our operations are subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources, and health and safety. Compliance with these legal requirements requires us to commit significant capital toward permitting, emission fees, environmental monitoring, installation and operation of pollution control equipment and purchase of allowances and/or offsets. Additionally, we could be responsible for expenses relating to remediation and containment obligations, including at sites where we have been identified by a regulatory agency as a PRP. Our expenditures relating to environmental compliance have been significant in the past, and we expect that they will remain significant in the future. Costs of compliance with environmental regulations could adversely affect our results of operations and financial condition, especially if emission and/or discharge limits are tightened, more extensive permitting requirements are imposed, additional substances become regulated and the number and types of assets we operate increases. We cannot estimate our compliance costs with certainty due to our inability to predict the requirements and timing of implementation of any new environmental rules or regulations related to emissions. Other factors which affect our ability to predict our future environmental expenditures with certainty include the difficulty in estimating clean-up costs and quantifying liabilities under environmental laws that impose joint and several liability on all responsible parties.

If federal and/or state requirements are imposed on energy companies mandating further emission reductions, including limitations on CO₂ emissions, such requirements could make some of our electric generating units uneconomical to maintain or operate. Environmental advocacy groups, other organizations and some agencies are focusing considerable attention on CO₂ emissions from power generation facilities and their potential role in climate change. We expect that federal legislation, and possibly additional state legislation, may pass resulting in the imposition of limitations on GHG emissions from fossil fuel-fired electric generating units. Such limits could make certain of our electric generating units uneconomical to operate in the long term, unless there are significant advancements in the commercial availability and cost of carbon capture and storage technology. There are also potential impacts on our natural gas businesses as federal GHG legislation may require GHG emission reduction requirements from the

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

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

Delays in the recovery of fuel costs at our regulated electric utility could negatively affect our electric utility’s cash flow, which could adversely affect our results of operations. Our regulated electric utility has a statutory right to recover from customers all prudently incurred fuel costs through fuel factors which have been implemented in our Virginia and North Carolina jurisdictions. However, as a result of increasing fuel costs and a statutory limitation on the amount of fuel recovery that could be collected from Virginia jurisdictional customers in the July 1, 2007 through June 30, 2008 fuel factor period, our electric utility has deferred a significant amount of fuel costs. Deferred recovery of fuel costs could have a negative impact on the cash flow of our electric utility. The recent fluctuations in fuel prices may make it difficult to accurately predict fuel costs. In the future, if actual fuel costs incurred during the fuel factor period exceed the esti

mate of costs which the Virginia Commission has approved for recovery in that period, we will not have authority to recover the excess costs through fuel rates until the following year when a new factor is determined. To the extent that such deferrals occur, the resulting delays in the current recovery of fuel costs could negatively impact the cash flow of our electric utility, which could adversely affect our results of operations.

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

Our wholesale charges for electric transmission service are adjusted on an annual basis through operation of a FERC-approved formula rate mechanism. Through this mechanism our wholesale electric transmission cost of service is estimated and thereafter trued-up as appropriate to reflect actual costs allocated to the Company by PJM. These wholesale rates are subject to FERC review and prospective adjustment in the event that customers and/or interested state commissions file a complaint with FERC and are able to demonstrate that our wholesale revenue requirement is no longer just and reasonable.

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

Energy conservation could negatively impact our financial results. Certain regulatory and legislative bodies have introduced or are considering requirements and/or incentives to reduce energy consumption by a fixed date. To the extent conservation resulted in reduced energy demand or significantly slowed the growth in demand, the value of our merchant generation, E&P assets and other unregulated business activities could be adversely impacted. In our regulated operations, conservation could negatively impact Dominion depending on the regulatory treatment of the associated impacts. Should we be required to invest in conservation measures that resulted in reduced sales from effective conservation, regulatory lag in adjusting rates for the impact of these measures could have a negative financial impact. We are unable to determine what impact, if any, conservation will have on our financial condition or results of operations.

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 including our ability to purchase and sell power at prices sufficient to cover our operating costs. We operate in active wholesale markets that expose us to price volatility for electricity and fuel as well as the credit risk of counterparties. We attempt to manage our price risk by entering into hedging transactions, including short-term and long-term fixed price sales and purchase contracts.

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

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

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

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

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

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

There are risks associated with the operation of nuclear facilities. We operate nuclear facilities that are subject to risks, including our 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 decommissioning costs could exceed the amount in our trusts or that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses and liquidity constraints. We use derivative instruments, including futures, swaps, forwards, options and financial transmission rights (FTRs) to manage our commodity and financial market risks. In addition, we purchase and sell commodity-based contracts primarily in the natural gas market 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 our electric and gas operations. The use of such derivatives to hedge future electric and gas sales 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. For instance, 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 or 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 9 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, drilling cost pressures, operational risks that could disrupt production, drilling rig availability and geological and other uncertainties inherent in the estimate of gas and oil reserves.

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.

We may not complete plant construction or expansion projects that we commence, or we may complete projects on materially different terms or timing than initially anticipated and we may not be able to achieve the intended benefits of any such project, if completed. We have announced several plant construction and expansion projects and may consider additional projects in the future. We anticipate that we will be required to seek additional financing in the future to fund our current and future plant construction and expansion projects and we may not be able to secure such financing on favorable terms. In addition, we may not be able to complete the projects on time as a result of weather conditions, delays in obtaining or failure to obtain regulatory approvals, delays in obtaining key materials, labor difficulties, difficulties with partners or potential partners, a decline in the credit strength of our counterparties or vendors, or other factors beyond our control. With respect to our LNG and gas transmission pipeline operations, if we do not meet designated schedules for approval and construction of our plant and expansion projects, certain of our customers may have the right to terminate their precedent agreements relating to the expansion projects. Certain of our customers may also have the right to receive liquidated damages. Even if plant construction and expansion projects are completed, the total costs of the projects may be higher than anticipated and the performance of our business following the projects may not meet expectations. Additionally, regulators may disallow recovery of some of the costs of a project if they are deemed not to be prudently incurred. Further, we may not be able to timely and effectively integrate the projects into our operations and such integration may result in unforeseen operating difficulties or unanticipated costs. Any of these or other factors could adversely affect our ability to realize the anticipated benefits from the plant construction and expansion projects.

An inability to access financial markets could affect the execution of our business plan. Dominion and our subsidiary, Virginia Power, rely on access to short-term money markets, longer-term capital markets and banks as significant sources of funding and liquidity for capital expenditures, normal working capital and collateral requirements related to hedges of future sales and purchases of energy-related commodities primarily associated with our merchant generation and gas and oil production. Management believes that Dominion and Virginia Power will maintain sufficient access to these financial markets based upon our current credit ratings and market reputation. However, certain dis-

ruptions 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 a continuation of the current economic downturn, the bankruptcy of an unrelated company, general market disruption due to general credit market or political events, changes to our credit ratings or the failure of financial institutions on which we rely. Restrictions on our ability to access financial markets may affect our ability to execute our business plan as scheduled.

Market performance and other changes may decrease the value of decommissioning trust funds and benefit plan assets or increase our liabilities, which then could require significant additional funding. The performance of the capital markets affects the value of the assets that are held in trust to satisfy future obligations to decommission our nuclear plants and under our pension and postretirement benefit plans. We have significant obligations in these areas and hold significant assets in these trusts. These assets are subject to market fluctuation and will yield uncertain returns, which may fall below our expected return rates. A decline in the market value of the assets may increase the funding requirements of the obligations to decommission our nuclear plants and under our pension and postretirement benefit plans. Additionally, changes in interest rates affect the liabilities under our pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. Further, changes in demographics, including increased numbers of retirements or changes in life expectancy assumptions, may also increase the funding requirements of the obligations related to the pension benefit plans. If the decommissioning trust funds and benefit plan assets are not successfully managed, our results of operations and financial condition could be negatively affected.

Changing rating agency requirements could negatively affect our growth and business strategy. As of February 1, 2009, Dominion’s senior unsecured debt is rated A-, stable outlook, by Standard & Poor’s; Baa2, stable outlook, by Moody’s; and BBB+, stable outlook, by Fitch. 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 subsidiary 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 strategy is dependent on our ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect our business and future operating results.

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 October 2003, the EPA and MADEP each issued new NPDES permits for Brayton Point. The new permits contained identical conditions that in effect require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. Following various appeals by Brayton Point, in December 2007, the EPA issued an administrative order to Brayton Point that contained a schedule for implementing the permit. On the same day, Brayton Point withdrew its appeal of the permit from the U.S. Court of Appeals, and in March 2008, the related state appeal of the permit was also dismissed.

In December 2006 and January 2007, we submitted self-disclosure notifications to EPA Region 8 regarding three E&P facilities in Utah that potentially violated CAA permitting requirements. In July 2007, a third party purchased Dominion’s E&P assets in Utah, including these facilities. In September 2008, we received a draft Consent Decree related to the potential CAA infractions, which imposes obligations on our subsidiary, DEPI and the purchaser, including payment of a civil penalty to the DOJ in the amount of $250,000. We expect the Consent Decree will be executed during the first quarter of 2009, after which it will be posted for public notice and comment for a period of not less than thirty days. Following the execution of the Consent Decree and the expiration of the 30-day public notice and comment period, the DOJ may request the federal judge in this proceeding to enter a final Consent Decree. Per our asset purchase agreement, the third-party purchaser assumed responsibility for the resolution of any enforcement action or Consent Decree, including penalties.

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

None.