Dominion Energy - 10-K annual report

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

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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.

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 underRegulation, 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

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

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

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

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

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

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 OFENERGY 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

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.

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:

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

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

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

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.

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

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

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

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

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

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 electricitymarkets 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.

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-

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.

MD&A discusses our results of operations and general financial condition. MD&A should be read in conjunction with Item 1. Business and our Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data. 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.

CONTENTS OF MD&A

Our MD&A consists of the following information:

FORWARD-LOOKINGSTATEMENTS

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

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

activities are complex and may be subject to further clarification by standard-setting bodies. The majority of investments held in our nuclear decommissioning and rabbi trust funds are also subject to fair value accounting. Assets held in our pension and other postretirement benefit plans are subject to the fair value measurement requirements of SFAS No. 157, but are currently not subject to fair value disclosure requirements. Therefore they are not included in the level summaries presented below. See Note 8 of our Consolidated Financial Statements for further information on our fair value measurements.

Fair value is based on actively-quoted market prices, if available. In the absence of actively-quoted market prices, we seek indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, or if we believe that observable pricing information is not indicative of fair value, judgment is required to develop the estimates of fair value. In those cases we must estimate prices based on available historical and near-term future price information and use of statistical methods, including regression analysis that reflect our market assumptions.

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

In accordance with SFAS No. 157, we maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. We utilize the following fair value hierarchy as prescribed by SFAS No. 157, which categorizes the inputs used to measure fair value into three levels:

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

Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 primarily include non-exchange traded derivatives such as over-the-counter com-

In April of each year, we test our goodwill for potential impairment, and perform additional tests more frequently if an event occurs or circumstances change in the interim that would more likely than not reduce the fair value of a reporting unit below its carrying amount. The 2008, 2007 and 2006 annual tests did not result in the recognition of any goodwill impairment.

As a result of the 2007 disposition of our non-Appalachian E&P operations, goodwill was allocated to such operations based on the relative fair values of the E&P operations being disposed of and the Appalachian portion being retained. The impairment test performed on the goodwill allocated to the retained Appalachian operations showed no impairment. Also, in connection with the 2007 segment realignment, the goodwill allocated to our three gas distribution subsidiaries was tested for impairment during the fourth quarter of 2007. This interim test did not result in the recognition of any goodwill impairment, as the estimated fair values of these businesses exceeded their respective carrying amounts. There were no significant changes to goodwill during the year ended December 31, 2008.

In general, we estimate the fair value of our reporting units by using a combination of discounted cash flows, and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. For our non-Appalachian E&P operations, our regulated gas distribution subsidiaries held for sale and certain DCI operations, negotiated sales prices were used as fair value for the tests conducted in 2008 and 2007. Fair value estimates are dependent on subjective factors such as our estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in our estimates of future cash flows, could result in a future impairment of goodwill. Although we have consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the most recent tests had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units tested, indicating that no impairment was present.

USE OF ESTIMATES IN LONG-LIVED ASSET IMPAIRMENT TESTING

Impairment testing for an individual or group of long-lived assets or for intangible assets with definite lives is required when circumstances indicate those assets may be impaired. When an asset’s carrying amount exceeds the undiscounted estimated future cash flows associated with the asset, the asset is considered impaired to the extent that the asset’s fair value is less than its carrying amount. Performing an impairment test on long-lived assets involves judgment in areas such as identifying circumstances that indicate an impairment may exist; identifying and grouping affected assets; and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value

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

ACCOUNTING FOR REGULATED OPERATIONS

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

As discussed further in Note 2 to our Consolidated Financial Statements, in April 2007, the Virginia General Assembly passed legislation that returned the Virginia jurisdiction of our utility generation operations to cost-of-service rate regulation. As a result, we reapplied the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, to those operations on April 4, 2007, the date the legislation was enacted. The reapplication of SFAS No. 71 to the Virginia jurisdiction of our utility generation operations resulted in a $259 million ($158 million after tax) extraordinary charge and the reclassification of $195 million ($119 million after tax) of unrealized gains from AOCI related to nuclear decommissioning trust funds. This established a $454 million long-term regulatory liability for amounts previously collected from Virginia jurisdictional customers and placed in external trusts (including income, losses and changes in fair value thereon) for the future decommissioning of our utility nuclear generation stations, in excess of amounts recorded pursuant to SFAS No. 143, Accounting for Asset Retirement Obligations. In connection with the reapplication of SFAS No. 71, we prospectively changed certain of our accounting policies for the Virginia jurisdiction of our utility generation operations to those used by cost-of-service rate-regulated entities. Other than the extraordinary item previously discussed, the overall impact of these changes was not material to our results of operations or financial condition in 2007.

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

We determine cost escalation rates, which represent projected cost increases over time, due to both general inflation and increases in the cost of specific decommissioning activities, for each of our nuclear facilities. The use of alternative rates could have been material to the liabilities recognized. For example, had we increased the cost escalation rate by 0.5%, the amount recognized as of December 31, 2008 for our AROs related to nuclear decommissioning would have been $290 million higher.

EMPLOYEE BENEFIT PLANS

We sponsor noncontributory defined benefit pension plans and other postretirement benefit plans for eligible active employees, retirees and qualifying dependents. The projected costs of providing benefits under these plans are dependent, in part, on historical information such as employee demographics, the level of contributions made to the plans and earnings on plan assets. Assumptions about the future, including the expected long-term rate of return on plan assets, discount rates applied to benefit obligations and the anticipated rate of increase in health care costs and participant compensation, also have a significant impact on employee benefit costs. The impact of changes in these factors, as well as differences between our assumptions and actual experience, is generally recognized in our Consolidated Statements of Income over the remaining average service period of plan participants, rather than immediately.

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

Strategic investment policies are established for each of our prefunded benefit plans based upon periodic asset/liability studies. Factors considered in setting the investment policy include those mentioned above such as employee demographics, liability growth rates, future discount rates, the funded status of the plans and the expected long-term rate of return on plan assets. Deviations from

activities are capitalized and subsequently depleted using the units-of-production method. The depletable base of costs includes estimated future costs to be incurred in developing proved gas and oil reserves, as well as capitalized asset retirement costs, net of projected salvage values. Capitalized costs in the depletable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves, discounted at 10%, assuming period-end pricing adjusted for any cash flow hedges in place. We perform the ceiling test quarterly and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. Commodity prices have declined during the first quarter of 2009. If the current price environment continues, it could potentially result in a write-down of our natural gas and oil properties when we perform our March 31, 2009 quarterly ceiling test. While we cannot currently predict the impact of a ceiling test impairment on our results of operations, it would have no impact on our cash flows and we would not expect a material impact on our financial condition. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a country. In 2007, we recognized gains from the sales of our Canadian and U.S. non-Appalachian E&P businesses. See Note 5 to our Consolidated Financial Statements for additional information on these sales.

Our estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. Our estimated proved reserves as of December 31, 2008 are based upon studies for each of our properties prepared by our staff engineers and audited by Ryder Scott Company, L.P. Calculations were prepared using standard geological and engineering methods generally accepted by the petroleum industry and in accordance with SEC guidelines. Given the volatility of natural gas and oil prices, it is possible that our estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could materially change in the near-term.

The process to estimate reserves is imprecise, and estimates are subject to revision. If there is a significant variance in any of our estimates or assumptions in the future and revisions to the value of our proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2 and 27 to our Consolidated Financial Statements for additional information on our gas and oil producing activities.

INCOME TAXES

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

RESULTS OFOPERATIONS

Presented below is a summary of our consolidated results:

Overview

2008VS. 2007

Net income decreased by 28% to $1.8 billion. Unfavorable drivers include the absence of a $2.1 billion after-tax gain on the sale of our U.S. non-Appalachian E&P business and the absence of ongoing earnings from this business due to the sale. Favorable drivers include the absence of the following items incurred in 2007:

Additional favorable drivers include the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of our utility generation operations effective July 1, 2007, a higher contribution from our merchant generation operations and the reversal of deferred tax liabilities associated with the planned sale of Peoples and Hope. Diluted EPS decreased to $3.16 and includes $0.36 of share accretion resulting from the repurchase of shares in 2007 with proceeds received from the sale of the majority of our E&P operations.

2007VS. 2006

Net income increased by 84% to $2.5 billion. Diluted EPS increased to $3.88 and includes $0.24 of share accretion resulting from the repurchase of shares with proceeds received from the sale of our non-Appalachian E&P business. Favorable drivers include a gain on the sale of our non-Appalachian E&P business, higher realized prices for our gas and oil production, higher margins at our merchant generation business and the reinstatement of annual fuel rate adjustments for the Virginia jurisdiction of our utility generation operations. Unfavorable drivers include a decrease in gas and oil production due to the sale of our non-Appalachian E&P business, an impairment charge related to the sale of Dresden, an extraordinary charge in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our utility generation operations, charges related to the early extinguishment of outstanding debt associated with the completion of our debt tender offer in July 2007, a charge due to the discontinuance of hedge accounting for certain gas and oil derivatives and subsequent changes in the fair value of these derivatives as a result of the sale of our non-Appalachian E&P business, a charge for the termination of a long-term power sales agreement at State Line and the absence of business interruption insurance revenue received in 2006, associated with Hurricanes Katrina and Rita (2005 hurricanes).

These increases were partially offset by:

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 18% to $4.0 billion, primarily reflecting the combined effects of:

Extraordinary item reflects the absence of a $158 million after-tax charge in 2007 in connection with the reapplication of SFAS No. 71 to the Virginia jurisdiction of our utility generation operations.

2007 VS. 2006

Operating Revenue decreased 14% to $14.8 billion, primarily reflecting:

These decreases were partially offset by:

These decreases were partially offset by:

Other energy-related commodity purchases expense decreased 75% to $252 million, primarily attributable to the following factors:

Other operations and maintenance expense increased 14% to $4.1 billion, resulting primarily from:

Gain on sale of U.S. non-Appalachian E&P business reflects a pre-tax gain of $3.6 billion resulting from the completion of the sale of our U.S. non-Appalachian E&P business.

DD&A decreased 12% to $1.4 billion, principally due to decreased oil and gas production resulting from the sale of our U.S. non-Appalachian E&P business ($297 million); partially offset by an increase in DD&A rates for our remaining Appalachian E&P business ($124 million).

Other income decreased 41% to $102 million, resulting primarily from the recognition of decommissioning trust earnings as a regulatory liability due to the reapplication of SFAS No. 71 to the Virginia jurisdiction of our utility generation operations, as well as an increase in charitable contributions.

Interest and related charges increased 8% to $1.2 billion, resulting principally from charges related to the early extinguishment of outstanding debt associated with our debt tender offer completed in July 2007, partially offset by a reduction in interest expense resulting from the retirement of this and other debt and the absence of a $60 million charge in 2006 due to the elimination of hedge accounting for certain interest rate swaps associated with our junior subordinated notes payable to affiliated trusts.

Income tax expense increased to $1.8 billion, primarily reflecting income tax expense on the gain realized from the sale of our U.S. non-Appalachian E&P business.