10-K 1 d10k.htm DOMINION RESOURCES, INC DOMINION RESOURCES, INC
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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 


 

FORM 10-K

 

(Mark One)

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended December 31, 2004

 

OR

 

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the transition period from                      to                     

 

Commission File Number 1-8489

 


 

DOMINION RESOURCES, INC.

(Exact name of registrant as specified in its charter)

 

Virginia   54-1229715
(State or other jurisdiction
of incorporation or organization)
  (I.R.S. Employer
Identification No.)

120 Tredegar Street

Richmond, Virginia

  23219
(Address of principal executive offices)   (Zip Code)

 

(804) 819-2000

(Registrant’s telephone number)

 


 

Securities registered pursuant to Section 12(b) of the Act:

 

Title of Each Class


 

Name of Each Exchange

on Which Registered


Common stock, no par value   New York Stock Exchange
8.75% Equity income securities, $50 par   New York Stock Exchange
8.4% Trust preferred securities, $25 par   New York Stock Exchange

 

Securities registered pursuant to Section 12(g) of the Act:

None

 


 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

 

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

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). Yes  x    No  ¨

 

The aggregate market value of the common stock held by non-affiliates of the registrant was approximately $20.8 billion based on the closing price of Dominion’s common stock as reported on the New York Stock Exchange as of the last day of the registrant’s most recently completed second fiscal quarter.

 

As of February 1, 2005, Dominion had 340,591,545 shares of common stock outstanding.

 

DOCUMENT INCORPORATED BY REFERENCE.

 

(a)   Portions of the 2005 Proxy Statement are incorporated by reference in Part III.

 



Table of Contents

Dominion Resources, Inc.

 

Item

Number

         Page
Number
Part I       

1.

  Business      1

2.

  Properties      11

3.

  Legal Proceedings      14

4.

  Submission of Matters to a Vote of Security Holders      14

Executive Officers of the Registrant

     15
Part II       

5.

  Market for the Registrant’s Common Equity and Related Stockholder Matters      16

6.

  Selected Financial Data      16

7.

  Management’s Discussion and Analysis of Financial Condition and Results of Operations      17

7A.

  Quantitative and Qualitative Disclosures About Market Risk      46

8.

  Financial Statements and Supplementary Data      47

9.

  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure      93

9A.

  Controls and Procedures      93

9B.

  Other Information      93
Part III       

10.

  Directors and Executive Officers of the Registrant      94

11.

  Executive Compensation      94

12.

  Security Ownership of Certain Beneficial Owners and Management      94

13.

  Certain Relationships and Related Transactions      94

14.

  Principal Accountant Fees and Services      94
Part IV       

15.

  Exhibits and Financial Statement Schedules      95


Table of Contents

Part 1

 

Item 1. Business

The Company

Dominion Resources, Inc. (Dominion) is a fully integrated gas and electric holding company headquartered in Richmond, Virginia. Incorporated in Virginia in 1983, Dominion is a registered public utility holding company under the Public Utility Holding Company Act of 1935 (the 1935 Act).

Dominion concentrates its efforts largely in what Dominion refers to as the “MAIN to Maine” region. In the power industry, “MAIN” means the Mid-America Interconnected Network, which comprises all of Illinois and portions of the states of Missouri, Iowa, Wisconsin, Michigan and Minnesota. Under this strategy, Dominion focuses its efforts on the region stretching from MAIN, through its primary Mid-Atlantic service areas in Ohio, Pennsylvania, West Virginia, Virginia and North Carolina, and up through New York and New England. The MAIN-to-Maine region is home to approximately 40% of the nation’s demand for energy.

The term “Dominion” is used throughout this report and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc., one of Dominion Resources, Inc.’s consolidated subsidiaries or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

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

As of December 31, 2004, Dominion and its subsidiaries had approximately 16,500 full-time employees. Approximately 6,000 employees are subject to collective bargaining agreements. The contracts of employees represented by the Utility Workers’ Union of America, United Gas Workers’ Local 69-II, AFL-CIO (Local 69-II) expire April 1, 2005. Dominion and Local 69-II have begun negotiations for new contracts.

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

 

Operating Segments

Dominion manages its operations through four primary business lines that integrate its electric and gas services, streamline operations and position it for long-term growth in the competitive marketplace: Dominion Delivery, Dominion Energy, Dominion Exploration & Production and Dominion Generation. Dominion also reports Corporate and Other functions as a segment. While Dominion manages its daily operations as described below, its assets remain wholly-owned by its legal subsidiaries. For additional financial information on business segments and geographic areas, see Note 27 to the Consolidated Financial Statements.

 

Dominion Delivery

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

 

Competition

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

Deregulation is at varying stages in the three states in which Dominion’s gas distribution subsidiaries operate. In Pennsylvania, supplier choice is available for all residential and small commercial customers. In Ohio, legislation has not been enacted to require supplier choice for residential and commercial natural gas consumers. However, Dominion offers an Energy Choice program to customers on its own initiative, in cooperation with the Public Utilities Commission of Ohio (Ohio Commission). West Virginia does not require customer choice in its retail natural gas markets at this time. See Regulation—State Regulations for additional information.

 

Regulation

Dominion Delivery’s electric retail service, including the rates it may charge to customers, is subject to regulation by the Virginia State Corporation Commission (Virginia Commission) and the North Carolina Utilities Commission (North Carolina Commission). See Regulation—State Regulations-Electric for additional information.

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

 

Properties

Dominion Delivery’s electric distribution network includes approximately 54,000 miles of distribution lines, exclusive of service level lines, in Virginia and North Carolina. The right-of-way grants for most electric lines have been obtained from the apparent owner of real estate, but underlying titles have not been examined except for transmission lines of 69 kV or more. Where rights-of-way have not been obtained, they could be acquired from private owners by condemnation, if necessary. Many electric lines are on publicly owned property, where permission to operate can be revoked.

 

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Dominion Delivery’s investment in its gas distribution network is located in the states of Ohio, Pennsylvania and West Virginia. The gas distribution network involves approximately 27,000 miles of pipe, exclusive of service pipe, and 203 billion cubic feet (bcf) of underground gas storage capacity in Ohio, Pennsylvania and West Virginia. See Dominion Energy—Properties for additional information regarding Dominion Delivery’s storage properties.

 

Sources of Fuel Supply

Dominion Delivery’s supply of electricity to serve its retail customers is primarily provided by Dominion Generation. See Dominion Generation for additional information.

Dominion Delivery is engaged in the sale and storage of natural gas through its operating subsidiaries. Dominion Delivery’s gas 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 Dominion’s and third party underground storage fields.

 

Seasonality

Dominion Delivery’s business typically varies seasonally based on demand for electricity by residential and commercial customers for cooling and heating use based on changes in temperature. The same is true for gas sales based on heating needs.

 

Dominion Energy

Dominion Energy includes the following operations:

  A regulated interstate gas transmission pipeline and storage system, serving Dominion’s gas distribution businesses and other customers in the Midwest, the Mid-Atlantic states and the Northeast;
  A regulated electric transmission system principally located in Virginia and northeastern North Carolina;
  An LNG import and storage facility in Maryland;
  Certain gas production operations located in the Appalachian basin; and
  Clearinghouse, which is responsible for energy trading, marketing, hedging, arbitrage, and gas aggregation activities.

During the fourth quarter of 2004, Dominion performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenues and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As a result of these changes, 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities in the Dominion Generation segment.

 

Competition

Dominion Energy’s electric transmission business is not subject to competition for transmission service to loads served within its Virginia and North Carolina service territories. In connection with transmission service to loads outside of its electric service territory, Dominion’s electric transmission business competes with other electric transmission providers, primarily on the basis of rates and availability of service.

Dominion Energy’s gas transmission operations compete with domestic and Canadian pipeline companies and gas marketers seeking to provide or arrange transportation, storage and other services for customers. 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 longline pipelines, a large storage capability and the availability of numerous receipt and delivery points along its own pipeline system enables Dominion to tailor its services to meet the needs of individual customers.

 

Regulation

Dominion Energy’s electric transmission operations are subject to regulation by the Federal Energy Regulatory Commission (FERC), the Virginia Commission and the North Carolina Commission. FERC also regulates Dominion’s natural gas pipeline transmission, storage and LNG operations. See State Regulations and Federal Regulations in Regulation for additional information.

 

Properties

Dominion Energy has approximately 6,000 miles of electric transmission lines located in the states of North Carolina, Virginia and West Virginia. Portions of Dominion Energy’s electric transmission lines cross national parks and forests under permits entitling the federal government to use, at specified charges, surplus capacity in the line, if any exists.

Dominion maintains major electric transmission interconnections with Progress Energy, American Electric Power Company, Inc., PJM-West and PJM. Through this major transmission network, Dominion has arrangements with these entities for coordinated planning, operation, emergency assistance and exchanges of capacity and energy. See also Regional Transmission Organization (RTO) in Future Issues and Other Matters in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A).

Dominion Energy has approximately 7,900 miles of gas transmission, gathering and storage pipelines located in the states of Maryland, New York, Ohio, Pennsylvania, Virginia and West Virginia.

Dominion’s storage operations involve both the Dominion Delivery and Dominion Energy segments. Storage operations include 26 underground gas storage fields located in New York, Ohio, Pennsylvania and West Virginia, with more than 2,000 storage wells and approximately 372,000 acres of operated leaseholds. Dominion Energy and Dominion Delivery together have more than 100 compressor stations with approximately 626,000 installed compressor horsepower. The total designed capacity of the underground storage fields is approximately 965 bcf of which 203 bcf is operated by Dominion Delivery and 762 bcf is operated by Dominion Energy. Six of the 26 storage fields are jointly-owned with other companies and have a capacity of 243 bcf. Dominion Energy also has approximately 8 bcf of above ground storage capacity at its Cove Point LNG facility.

The map below illustrates Dominion’s gas transmission pipelines, storage facilities, LNG facility and electric transmission lines.

 

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LOGO

 

Sources of Energy Supply

Dominion’s large underground natural gas storage network and the location of its pipeline system are a significant link between the country’s major gas pipelines and large markets in the Northeast and Mid-Atlantic regions and on the East Coast. Dominion’s pipelines are part of an interconnected gas transmission system, which continues to provide local distribution companies, marketers, power generators and industrial and commercial customers accessibility to supplies nationwide.

Dominion’s underground storage facilities play an important part in balancing gas supply with consumer demand and are essential to serving the Midwest, Mid-Atlantic and Northeast regions. In addition, storage capacity is an important element in the effective management of both gas supply and pipeline transport capacity.

 

Seasonality

Dominion Energy’s business is affected by seasonal changes in the prices of commodities that it actively markets and trades.

 

Dominion Exploration & Production

Dominion Exploration & Production includes Dominion’s gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico, and Western Canada.

 

Competition

Dominion Exploration & Production’s competitors range from major, international oil companies to smaller, independent producers. Dominion Exploration & Production faces significant competition in the bidding for federal offshore leases and in obtaining leases and drilling rights for onshore properties. Since Dominion Exploration & Production is the operator of a number of properties, it also faces competition in securing drilling equipment and supplies for exploration and development.

In terms of its production activities, Dominion Exploration & Production sells most of its deliverable natural gas and oil into short and intermediate-term markets. Dominion Exploration & Production faces challenges related to the marketing of its natural gas and oil production due to the contraction of participants in the energy marketing industry. However, Dominion Exploration & Production owns a large and diverse natural gas and oil portfolio and maintains an active gas and oil marketing presence in its primary production regions, which strengthens its knowledge of the marketplace and delivery options.

 

Regulation

Dominion’s exploration and production operations are subject to regulation by numerous federal and state authorities. The pipeline transportation of Dominion’s natural gas production is regulated by FERC and pipelines operating on or across the Outer Continental Shelf are subject to the Outer Continental Shelf Lands

 

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Act, which requires open-access, non-discriminatory pipeline facilities. Dominion’s production operations in the Gulf of Mexico and most of its operations in the western United States are located on federal oil and gas leases administered by the Minerals Management Service (MMS) or the Bureau of Land Management. These leases are issued through a competitive bidding process and require Dominion’s compliance with stringent regulations. Offshore production facilities must comply with MMS regulations relating to engineering, construction and operational specifications and the plugging and abandonment of wells. Dominion’s production operations are also subject to numerous environmental regulations including regulations relating to oil spills into navigable waters of the United States. See Regulation—Federal Regulations and Regulation—Environmental Regulation for additional information.

 

Properties

Dominion Exploration & Production owns 5.9 trillion cubic feet of proved equivalent natural gas reserves and produces approximately 1.2 billion cubic feet of equivalent natural gas per day from its leasehold acreage and facility investments. Dominion, either alone or with partners, holds interests in natural gas and oil leaseacreage, wellbores, well facilities, production platforms and gathering systems. Dominion also owns or holds rights to seismic data and other tools used in exploration and development drilling activities. Dominion’s share of developed leasehold totals 3.0 million acres, with another 2.2 million acres held for future exploration and development drilling opportunities. See also Item 2. Properties for additional information on Dominion Exploration & Production’s properties.

 

LOGO

       Note: Includes the activities of the Dominion Exploration & Production segment and the production activity of Dominion Transmission, Inc., which is included the Dominion Energy segment.
       Bcfe = billion cubic feet equivalent
       Mmcfe = million cubic feet equivalent

 

Seasonality

Dominion Exploration & Production’s business can be affected by seasonal changes in the demand for natural gas and oil. Commodity prices, including prices for unhedged Dominion natural gas and oil production, can be affected by seasonal weather changes and weather effects.

 

Dominion Generation

Dominion Generation includes more than 28,000 Mw of generation capability for Dominion’s electric utility and merchant fleet. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. Dominion’s strategy for its electric generation operations focuses on serving customers in the MAIN-to Maine-region. Its generation facilities are located in Virginia, West Virginia, North Carolina, Connecticut, Illinois, Indiana, Pennsylvania and Ohio. In addition, Dominion completed the acquisition of three USGen New England Inc. (USGen) power stations located in Massachusetts and Rhode Island during January 2005 and expects to complete the acquisition of the Kewaunee nuclear power plant located in northeastern Wisconsin during the first half of 2005. In addition, as discussed above, as a result of the reorganization of the

 

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Clearinghouse, Dominion Generation’s 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities by the Clearinghouse that were previously reported in the Dominion Energy segment.

 

Competition

For Dominion Generation’s electric utility subsidiary, retail choice has been available for all of Dominion’s Virginia electric customers since January 1, 2003; however, to date, competition in Virginia has not developed to the extent originally anticipated. See Regulation—State Regulations. Currently, North Carolina does not offer retail choice to electric customers.

Dominion Generation’s merchant generation fleet owns and operates three large facilities in the Midwest. These generating plants are all under long-term contracts and are therefore largely unaffected by competition.

The majority of Dominion Generation’s remaining merchant assets operates within functioning Independent System Operators (ISO). Competitors include other generating assets bidding to operate within the ISOs. These ISOs 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 any number of products including energy, capacity and operating reserves. It is difficult to compare various types of generation given the wide range of fuels, fuel procurement strategies, efficiencies, and operating characteristics of the fleet within any given ISO. However, management believes that Dominion has the expertise in operations, dispatch and risk management to maximize the degree to which its merchant fleet is competitive compared to like assets within the region.

 

Regulation

In Virginia and North Carolina, Dominion’s electric utility generation facilities, along with power purchases, are used to serve its utility service area obligations. Due to 2004 deregulation legislation, revenues for serving Virginia jurisdictional retail load are based on capped rates through 2010 and the related fuel costs for the generating fleet, including power purchases, are subject to a fixed rate recovery through July 1, 2007 when a one-time prospective adjustment will be considered. During this transition period, the risk of fuel factor-related cost recovery shortfalls may adversely impact Dominion’s cost structure. Conversely, Dominion may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs. Subject to market conditions, any generation remaining after meeting utility system needs is sold outside of Dominion’s service area. See Regulation—State Regulations and Regulation—Federal Regulations—Environmental Regulation for additional information.

 

Properties

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

 

Sources of Fuel Supply

Dominion Generation uses a variety of fuels to power its electric generation. These include a mix of both nuclear fuel and fossil fuel as described further below.

Nuclear Fuel—Dominion Generation utilizes primarily 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. 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 optimum cost and inventory levels.

Fossil Fuel—Dominion Generation utilizes coal, oil and natural gas in its fossil fuel operations. Dominion Generation’s coal supply is obtained through long-term contracts and spot purchases. Oil-fired generation are used primarily to support heavier system generation loads during very cold or very hot weather periods. Additional utility requirements are purchased mainly under short-term spot agreements.

Dominion Generation uses natural gas as needed throughout the year for Dominion’s utility and merchant generation facilities. Dominion’s gas 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 Dominion’s and third party underground storage fields.

Firm natural gas transportation contracts (capacity) exist that allow delivery of gas to Dominion Generation’s facilities. Dominion Generation’s capacity portfolio allows flexible natural gas deliveries to its gas turbine fleet, while minimizing costs.

 

Seasonality

Dominion Generation’s sales of electricity typically vary seasonally based on demand for electricity by residential and commercial customers for cooling and heating use based on changes in temperature.

 

Nuclear Decommissioning

Dominion Generation has a total of six licensed, operating nuclear reactors at its Surry and North Anna plants in Virginia and its Millstone plant in Connecticut. Surry and North Anna serve customers of Dominion’s regulated electric utility operations.

Millstone is a nonregulated merchant plant with two operating units. A third Millstone unit ceased operations before Dominion acquired the plant.

Decommissioning represents the decontamination and removal of radioactive contaminants from a nuclear power plant once operations have ceased, in accordance with standards established by the NRC. Amounts collected from ratepayers and placed in trusts are being invested to fund future costs of decommissioning the Surry and North Anna units. As part of its acquisition of Millstone, Dominion acquired the decommissioning trusts for the three units that were fully funded to the regulatory minimum as of the acquisition date. Currently, Dominion believes that the amounts available in the trusts and their expected earnings will be sufficient to cover

 

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expected decommissioning costs for the Millstone units, without any additional contributions to the trusts.

The total estimated cost to decommission Dominion’s seven nuclear units is $3.0 billion based upon site-specific studies completed in 2002. Dominion expects to perform new cost studies in 2006. For all units except Millstone Unit 1 and Unit 2, the current cost estimates assume decommissioning activities will begin shortly after cessation of operations, which will occur when operating licenses expire. Millstone Unit 1 is not in service and selected minor decommissioning activities are being performed. Millstone Unit 1 will be monitored until decommissioning activities begin for the remaining Millstone units. The current operating licenses expire in the years detailed in the following table. During 2003, the NRC approved Dominion’s application for a 20-year life extension for the Surry and North Anna units and Dominion has filed a similar request for the Millstone units in 2004. Dominion expects to decommission the Surry and North Anna units during the period 2032 to 2045 and the Millstone units during the period 2034 to 2057.

 

 

       Surry      North Anna      Millstone       
       Unit 1      Unit 2      Unit 1      Unit 2      Unit 1      Unit 2      Unit 3      Total
(millions)                                                        

NRC license expiration year

     2032      2033      2038      2040      (1 )    2015      2025       

Current cost estimate (2002 dollars)

     $375      $368      $391      $363      $531      $486      $518      $3,032

Funds in trusts at December 31, 2004

     313      308      256      242      279      315      310      2,023

2004 contributions to trusts

     11      11      7      7                     36

 

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

 

Corporate and Other

Dominion also has a Corporate and Other segment that includes:

  Dominion’s corporate, service company and other operations, including unallocated debt;
  The remaining assets of Dominion Capital, Inc., (DCI) a financial services subsidiary, which are being divested in accordance with a Securities and Exchange Commission (SEC) order;
  The net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004; and
  Specific items attributable to Dominion’s operating segments that are reported in Corporate and Other.

 

Business Developments

In January 2005, the Public Service Commission of Wisconsin granted Dominion’s request to rehear the case involving Dominion’s proposed purchase of the Kewaunee nuclear power plant, located in northeastern Wisconsin. The commission had voted to deny the sale in November 2004. During the fourth quarter of 2003, Dominion reached an agreement to buy the Kewaunee nuclear power plant from Wisconsin Public Service Corporation, a subsidiary of WPS Resources Corporation (WPS), and Wisconsin Power & Light Company (WP&L), a subsidiary of Alliant Energy Corporation for an aggregate purchase price of $220 million in cash, including $35 million for nuclear fuel. If approved by the commission, the transaction is expected to close in the first half of 2005.

In January 2005, Dominion closed on its purchase of three electric power generation facilities from USGen for $642 million. The acquisition was part of a bankruptcy court-approved divestiture of generation assets by USGen. The plants include the 1,521-megawatt Brayton Point Station in Somerset, Massachusetts; the 743-megawatt Salem Harbor Station in Salem, Massachusetts; and the 426- megawatt Manchester Street Station in Providence, Rhode Island.

In February 2005, Dominion paid $42 million in cash and assumed $62 million in debt in connection with the termination of a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary, LP, a non-utility generator, to provide electricity to Dominion.

See Kewaunee Power Plant, USGen Power Stations and Restructuring of Contract with Non-Utility Generator in Future Issues and Other Matters in MD&A for additional information on the above business developments.

 

Regulation

Dominion is subject to regulation by the SEC, FERC, the Environmental Protection Agency (EPA), the Department of Energy (DOE), the Nuclear Regulatory Commission (NRC), the Army Corps of Engineers, and other federal, state and local authorities.

 

State Regulations

Electric

Dominion’s electric retail service is subject to regulation by the Virginia Commission and the North Carolina Commission.

Dominion’s electric utility subsidiary holds certificates of public convenience and necessity authorizing it to maintain and operate its electric facilities now in operation and to sell electricity to customers. However, it may not construct or incur financial commitments for construction of any substantial generating facilities or large capacity transmission lines without the prior approval of various state and federal government agencies.

 

Status of Electric Deregulation in Virginia

The Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) was enacted in 1999 and established a plan to restructure the electric utility industry in Virginia. The Virginia Restructuring Act addressed, among other things: capped base rates, RTO participation, retail choice, the recovery of stranded costs and the functional separation of a utility’s electric generation from its electric transmission and distribution operations.

Retail choice has been available to all of Dominion’s Virginia regulated electric customers since January 1, 2003. Dominion has also separated its generation, distribution and transmission

 

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functions through the creation of divisions within Virginia Power. Codes of conduct ensure that Virginia Power’s generation and other divisions operate independently and prevent cross-subsidies between the generation and other divisions.

Since the passage of the Virginia Restructuring Act, the competitive environment has not developed in Virginia as anticipated. In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

  Lock in Dominion’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;
  Provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and
  End wires charges on the earlier of July 1, 2007 or the termination of capped rates, consistent with the Virginia Restructuring Act’s original timetable.

The risk of fuel factor-related cost recovery shortfalls may adversely impact its cost structure during the transition period and Dominion could realize the negative economic impact of any such adverse event. Conversely, Dominion may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs for its electric utility generation-related operations.

Dominion anticipates that its unhedged natural gas and oil production will act as a natural internal hedge for natural gas and oil fuel costs associated with electric generation. If natural gas and oil prices rise, it is expected that Dominion’s exploration and production operations will earn greater profits that will offset higher fuel costs and lower profits in Dominion’s electric generation operations. Conversely, if gas and oil prices fall, it is expected that Dominion’s electric generation operations will incur lower fuel costs and earn higher profits that will offset lower profits in Dominion’s exploration and production operations. Dominion also anticipates that the fixed fuel rate will lessen the impact of seasonally mild weather on its electric generation operations. During periods of mild weather it is expected that electric generation operations will burn less high-cost fuel because customers will use less electricity, thereby offsetting decreased revenues. Alternatively, in periods of extreme weather, Dominion’s higher fuel costs from running costlier plants are expected to be mitigated by additional revenue as customers use more electricity.

Other amendments to the Virginia Restructuring Act were also enacted with respect to a minimum stay exemption program, a wires charge exemption program and allowing the development of a coal-fired generating plant in southwest Virginia for serving default service needs. Under the minimum stay exemption program, large customers with a load of 500 kW or greater would be exempt from the twelve month minimum stay obligation under capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply service with a competitive service provider.

The wires charge exemption program would allow large industrial and commercial customers, as well as aggregated customers in all rate classes, to avoid paying wires charges when selecting supply service from a competitive service provider by agreeing to market-based pricing upon return to the incumbent electric utility. Customers electing this option would waive the right to return to capped rate service from the incumbent electric utility. The program is limited to the first 1,000 Mw of load or eight percent of the utility’s prior year Virginia adjusted peak load in the first 18 months of the program.

In January 2005, Dominion filed compliance plans and the required market-based pricing methodology for both programs. To encourage a successful program and the development of retail competition, Dominion has proposed that customers that enroll with a competitive service provider in the wires charge exemption program in 2005 be allowed to return to service with Dominion at capped rates after October 2007 instead of market-based pricing. The Virginia Commission must approve these proposals prior to implementation.

In December 2004, Dominion filed its annual market prices/wires charges compliance plan with the Virginia Commission. Calculation of the 2005 wires charges in accordance with the formula approved by the Virginia Commission produced zero wires charges for 2005 for all but a few smaller rate classes. As a result, Dominion voluntarily agreed to forego the collection of any wires charges during 2005. Dominion’s decision to forego wires charges in 2005 is not intended to set a precedent for subsequent periods. Dominion intends to collect wires charges in future periods should the Virginia Commission-approved methodology determine that wires charges are applicable.

See Regulation—Federal Regulations—Federal Energy Regulatory Commission and Status of Electric Deregulation in Virginia in Future Issues and Other Matters in MD&A for additional information on capped base rates, stranded costs and RTO participation.

 

Retail Access Pilot Programs

The three retail access pilot programs, approved by the Virginia Commission in 2003, continue to be available to customers. These programs are to run through the remainder of the capped rate period and will make available to competitive service providers up to 500 megawatts of load, with potential participation of more than 65,000 customers from a variety of customer classes.

 

Rate Matters

Virginia—In December 2003, the Virginia Commission approved Dominion’s proposed settlement of its 2004 fuel factor increase of $386 million. The settlement includes a recovery period for the under-recovery balance over three and a half years. Approximately $171 million of the $386 million was recovered in 2004 with $85 million to be recovered in 2005, $87 million in 2006 and $43 million in the first six months of 2007.

As a result of amendments to the Virginia Restructuring Act in 2004, Dominion’s capped based rates were extended to December 31, 2010. In addition, Dominion’s fuel factor provisions were frozen until July 1, 2007, after which they can be only adjusted once more through December 31, 2010. See Status of Electric Deregulation in Virginia above for additional information regarding the Virginia Restructuring Act amendments.

 

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North Carolina—In connection with the North Carolina Commission’s approval of the CNG acquisition, Dominion agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on Dominion’s electric utility operations. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. However in April 2004, the North Carolina Commission commenced an investigation into Dominion’s North Carolina base rates and subsequently ordered Dominion to file a general rate case to show cause why its North Carolina base rates should not be reduced. The rate case was filed in September 2004 and in February 2005, Dominion reached a tentative settlement with parties in the case that is subject to North Carolina Commission approval before becoming effective.

 

Gas

Dominion’s gas distribution service is regulated by the Ohio Commission, the Pennsylvania Commission and the West Virginia Commission .

 

Status of Gas Deregulation

Each of the three states in which Dominion has gas distribution operations has enacted or considered legislation regarding deregulation of natural gas sales at the retail level.

Ohio—Ohio has not enacted legislation requiring supplier choice for residential and commercial natural gas consumers. However, in cooperation with the Ohio Commission, Dominion on its own initiative offers retail choice to customers. At December 31, 2004, approximately 548,000 of Dominion’s 1.2 million Ohio customers were participating in this open-access program. 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. At December 31, 2004, approximately 88,000 residential and small commercial customers had opted for Energy Choice in Dominion’s Pennsylvania service area. Nearly all Pennsylvania industrial and large commercial customers buy natural gas from nonregulated suppliers.

West Virginia—At this time, West Virginia has not enacted legislation to require customer choice in its retail natural gas markets. However, the West Virginia Commission has issued regulations to govern pooling services, one of the tools that natural gas suppliers may utilize to provide retail customer choice in the future and has issued rules requiring competitive gas service providers to be licensed in West Virginia.

 

Rate Matters—Gas Distribution

Dominion’s gas distribution business subsidiaries are subject to regulation of rates and other aspects of their businesses by the states in which they operate—Pennsylvania, Ohio and West Virginia. When necessary, Dominion’s gas distribution subsidiaries seek general rate increases on a timely basis to recover increased operating costs. In addition to general rate increases, certain of Dominion’s gas distribution subsidiaries make routine separate filings with their respective state regulatory commissions to reflect changes in the costs of purchased gas. These purchased gas costs are generally subject to rate recovery through a mechanism that ensures dollar for dollar recovery of prudently incurred costs. Costs that are expected to be recovered in future rates are deferred as regulatory assets. The purchased gas cost recovery filings generally cover prospective one, three or twelve-month periods. Approved increases or decreases in gas cost recovery rates result in increases or decreases in revenues with corresponding increases or decreases in net purchased gas cost expenses.

Ohio—In December 2003, the Ohio Commission approved a joint application filed by Dominion and several other Ohio natural gas companies for recovery of bad debt expense via a rider known as a bad debt tracker. The tracker insulates Dominion from the effect of changes in bad debt expense, which is affected by the volatility of natural gas prices, weather and prices charged by competitive retail natural gas suppliers. The tracker is an adjustable rate that recovers the cost of bad debt in a manner similar to a gas cost recovery rate. Instead of recovering bad debt costs through its base rates, Dominion recovers all eligible bad debt expenses through the bad debt tracker and removes bad debt from base rates. Annually, Dominion assesses the need to adjust the tracker based on the preceding year’s actual bad debt expense.

Pennsylvania—In July 2004, the Pennsylvania Commission approve a settlement agreement between Dominion and the Office of Consumer Advocate (OCA) in which the OCA agreed to drop its appeal of a previous Pennsylvania Commission order that allowed Dominion to recover approximately $16.5 million in unrecovered purchased gas costs. As part of the settlement, all customer service and delivery charges will be fixed through December 31, 2008. Gas costs will continue to pass through to the customer through the purchased gas cost adjustment mechanism.

Federal Regulations

Public Utility Holding Company Act of 1935

Dominion is a registered holding company under the 1935 Act. The 1935 Act and related regulations issued by the SEC govern activities of Dominion and its subsidiaries with respect to the issuance and acquisition of securities, acquisition and sale of utility assets, certain transactions among affiliates, engaging in businesses activities not directly related to the utility or energy business and other matters.

Dominion became a registered public utility holding company when it completed the CNG acquisition in January 2000. The 1935 Act prohibits registered companies from owning businesses not directly related to utility or other energy operations. Dominion has substantially completed its exit of the core operating businesses of DCI, its financial services subsidiary, and continues to seek opportunities to divest the remaining assets. Currently, Dominion is required to divest of all remaining DCI holdings by January 2006.

 

Federal Energy Regulatory Commission

Electric

Under the Federal Power Act, FERC regulates wholesale sales of electricity and transmission of electricity in interstate commerce by public utilities. Dominion’s electric utility subsidiary sells electricity in the wholesale market under its market-based sales tariff authorized by FERC but does not make wholesale power sales under this tariff to loads located within its service territory. In addition, Dominion’s electric utility subsidiary has FERC approval of a tariff to sell wholesale power at capped rates based on its embedded cost of generation. This cost-based sales tariff could be used to sell to loads within or outside its service territory. Any

 

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such sales would be voluntary. Dominion’s sales of natural gas, liquid hydrocarbon by-products and oil in wholesale markets are not regulated by FERC.

The Virginia Restructuring Act requires that Dominion join an RTO, and FERC encourages RTO formation as a means to foster wholesale market formation. Dominion and PJM Interconnection, LLC (PJM) entered into an agreement in September 2002 that provides that, subject to regulatory approval and certain provisions, Dominion will become a member of PJM and transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region. In October 2004, FERC issued an order conditionally approving Dominion’s application to join PJM, and in November 2004, the Virginia Commission approved Dominion’s application to join PJM subject to certain terms and conditions. The North Carolina Commission evidentiary hearing was held in January 2005. Dominion cannot predict the outcome of this matter at this time.

In a separate order issued in September 2004, FERC granted authority to Dominion subsidiaries with market based rate authority to charge market based rates for sales of electric energy and capacity to loads located within the Company’s service territory upon its integration into PJM. For additional information, see RTO in Future Issues and Other Matters in MD&A.

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

In June 2004, FERC approved Dominion’s filing to provide optional backup supply service to competitive service providers serving retail customers, including the retail pilot programs, in Dominion’s service territory in Virginia. The filing addressed competitive service providers’ concerns with the availability of transmission capacity to move energy into Virginia. The backup supply service will allow competitive service providers to continue to serve their customers in Dominion’s service area in Virginia during periods of supply interruption. This is an interim solution until Dominion is integrated into PJM.

In August 2004, Dominion and FERC announced a settlement of a self-reported infraction of FERC regulations involving data sharing of non-public gas storage information. Under the settlement, Dominion paid a $500,000 civil penalty and refunded $4.5 million to its non-affiliated natural gas storage customers. In addition, Dominion agreed to enhance internal training and oversight of employees who handle non-public, market-sensitive data.

 

Gas

FERC regulates the transportation and sale for resale of natural gas in interstate commerce under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, as amended. Under the Natural Gas Act, FERC has authority over rates, terms and conditions of services performed by Dominion’s interstate gas pipeline subsidiaries, including Dominion Transmission, Inc. (DTI) and Dominion Cove Point LNG, LP. FERC also has jurisdiction over siting, construction and operation of natural gas import facilities and interstate natural gas pipeline facilities.

FERC Order 636 requires transmission pipelines to operate as open-access transporters and provide transportation and storage services on an equal basis for all gas suppliers, whether purchased from Dominion or from another gas supplier.

Dominion’s interstate gas transportation and storage activities are conducted in accordance with certificates, tariffs and service agreements on file with FERC.

Dominion is also subject to the Pipeline Safety Act of 2002, which includes new mandates regarding the inspection frequency for interstate and intrastate natural gas transmission and storage pipelines located in areas of high-density population where the consequences of potential pipeline accidents pose the greatest risk to people and their property. Dominion has evaluated its natural gas transmission and storage properties under the final regulations issued in December 2003 and has developed the required implementation plan including identification, testing and potential remediation activities.

Dominion implemented various rate filings, tariff changes and negotiated rate service agreements for its FERC-regulated businesses during 2004. In all material respects, these filings were approved by FERC in the form requested by Dominion and were subject to only minor modifications.

 

Environmental Regulations

Each operating segment faces substantial regulation and compliance costs with respect to environmental matters. For a discussion of significant aspects of these matters, including current and planned capital expenditures relating to environmental compliance, see Environmental Matters in Future Issues and Other Matters in MD&A. Additional information can also be found in Item 3. Legal Proceedings and Note 22 to the Consolidated Financial Statements.

From time to time Dominion may be identified as a potentially responsible party to a Superfund site. The EPA (or a state) can either (a) allow such a party to conduct and pay for a remedial investigation, feasibility study and remedial action or (b) conduct the remedial investigation and action and then seek reimbursement from the parties. Each party can be held jointly, severally and strictly liable for all costs. These parties can also bring contribution actions against each other and seek reimbursement from their insurance companies. As a result, Dominion may be responsible for the costs of remedial investigation and actions under the Superfund Act or other laws or regulations regarding the remediation of waste. Dominion does not believe that any currently identified sites will result in significant liabilities.

In January 2004, the EPA proposed additional regulations addressing pollution transport from electric generating plants as well as the regulation of mercury and nickel emissions. These regulatory actions, in addition to revised regulations to address regional haze, are expected to be finalized in 2005 and could require additional reductions in emissions from the Company’s fossil fuel-fired generating facilities. If these new emission reduction requirements are imposed, additional significant expenditures may be required.

 

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In March 2004, the State of North Carolina filed a petition under Section 126 of the Clean Air Act seeking the EPA to impose additional nitrogen oxide (NOX) and sulfur dioxide (SO2) reductions from electrical generating units in thirteen states, claiming emissions from the electrical generating units in those states are contributing to air quality problems in North Carolina. Dominion has electrical generating units in six of the states. The issues raised by North Carolina are already being addressed by the EPA in current regulatory initiatives. The EPA is expected to respond to the petition in 2005. Given the highly uncertain outcome and timing of future action, if any, by the EPA on this issue, Dominion cannot predict the financial impact, if any, on its operations at this time.

The United States Congress is considering various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under a variety of periods of up to 15 years. If these new proposals are adopted, additional significant expenditures may be required.

In July 2004, the EPA published new regulations that govern existing utilities that employ a cooling water intake structure, and whose flow levels exceed a minimum threshold. The EPA’s rule presents several compliance options. Dominion is evaluating information from certain of its existing power stations and expects to spend approximately $16 million over the next 5 years conducting studies and technical evaluations. Dominion cannot predict the outcome of the EPA regulatory process or state with any certainty what specific controls may be required.

Dominion has applied for or obtained the necessary environmental permits for the operation of its regulated facilities. Many of these permits are subject to re-issuance and continuing review.

 

Nuclear Regulatory Commission

All aspects of the operation and maintenance of Dominion’s nuclear power stations, which are part of the Dominion Generation segment, are regulated by the NRC. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the NRC determines that the public interest, health or safety so requires.

From time to time, the NRC adopts new requirements for the operation and maintenance of nuclear facilities. In many cases, these new regulations require changes in the design, operation and maintenance of existing nuclear facilities. If the NRC adopts such requirements in the future, it could result in substantial increases in the cost of operating and maintaining Dominion’s nuclear generating units.

The NRC also requires Dominion to decontaminate nuclear facilities once operations cease. This process is referred to as decommissioning, and Dominion is required by the NRC to be financially prepared. For information on Dominion’s decommissioning trusts, see Dominion Generation—Nuclear Decommissioning and Note 11 to the Consolidated Financial Statements.

 

Where You Can Find More Information About Dominion

Dominion files its annual, quarterly and current reports, proxy statements and other information with the SEC. Dominion’s SEC filings are available to the public over the Internet at the SEC’s web site at http://www.sec.gov. You may also read and copy any document Dominion files at the SEC’s public reference room at 450 Fifth Street, NW, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

Dominion’s website address is www.dom.com. Dominion makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and any amendments to those reports as soon as practicable after filing or furnishing the material with the SEC. You may also request a copy of these filings, at no cost, by writing or telephoning us at: Corporate Secretary, Dominion, 120 Tredegar Street, Richmond, Virginia 23219, Telephone (804) 819-2000.

 

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Item 2. Properties

Dominion leases its principal executive office in Richmond, Virginia as well as corporate offices in other cities in which its subsidiaries operate. It also owns two corporate offices in Richmond.

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

Substantially all of Dominion’s electric utility’s property is subject to the lien of the mortgage securing its First and Refunding Mortgage Bonds and certain of Dominion’s nonutility generation facilities are subject to liens.

Information detailing Dominion’s gas and oil operations presented below and on the following page includes the activities of the Dominion Exploration & Production segment and the production activity of Dominion Transmission, Inc.(DTI), which is included in the Dominion Energy segment:

 

Company-Owned Proved Gas and Oil Reserves

Estimated net quantities of proved gas and oil reserves at December 31 of each of the last three years were as follows:

 

       2004      2003      2002
       Proved
Developed
     Total
Proved
     Proved
Developed
     Total
Proved
     Proved
Developed
     Total
Proved

Proved gas reserves (bcf)

                                         

United States

     3,680      4,904      3,553      4,801      3,549      4,458

Canada

     96      99      453      568      486      640

Total proved gas reserves

     3,776      5,003      4,006      5,369      4,035      5,098

Proved oil reserves (000 bbl)

                                         

United States

     87,382      128,924      42,347      135,914      47,759      138,798

Canada

     11,459      19,674      17,407      34,020      18,064      30,432

Total proved oil reserves

     98,841      148,598      59,754      169,934      65,823      169,230

Total proved gas and oil reserves (bcfe)

     4,369      5,894      4,364      6,388      4,430      6,113

 

Certain subsidiaries of Dominion file Form EIA-23 with the DOE, which reports gross proved reserves, including the working interests share of other owners, for properties operated by such Dominion subsidiaries. The proved reserves reported in the table above represent Dominion’s share of proved reserves for all properties, based on Dominion’s ownership interest in each property. For properties operated by Dominion, the difference between the proved reserves reported on Form EIA-23 and the gross reserves associated with the Company-owned proved reserves reported in the table above, does not exceed five percent. Estimated proved reserves as of December 31, 2004 are based upon studies for each Dominion property prepared by Dominion’s staff engineers and reviewed by either Ralph E. Davis Associates, Inc. or 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.

 

Quantities of Gas and Oil Produced

Quantities of gas and oil produced during each of the last three years ending December 31 follow:

 

       2004      2003      2002

Gas production (bcf)

                    

United States

     327      346      346

Canada

     44      50      53

Total gas production

     371      396      399

Oil production (000 bbls)

                    

United States

     8,800      7,642      8,653

Canada

     1,201      1,081      1,072

Total oil production

     10,001      8,723      9,725

Total gas and oil production (bcfe)

     431      449      458

 

The average sales price per thousand cubic feet (mcf) of gas with hedging results (including transfers to other Dominion operations at market prices) realized during the years 2004, 2003 and 2002 was $4.14, $3.98 and $3.41, respectively. The respective average prices without hedging results per mcf of gas produced were $5.66, $5.02 and $3.04. The respective average sales prices realized for oil with hedging results were $24.99, $24.30 and $23.29 per barrel and the respective average prices without hedging results were $39.06, $29.82 and $24.45 per barrel. The average production (lifting) cost per mcf equivalent of gas and oil produced (as calculated per SEC guidelines) during the years 2004, 2003 and 2002 was $0.91, $0.80 and $0.60, respectively.

 

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Acreage

Gross and net developed and undeveloped acreage at December 31, 2004 was:

 

       Developed Acreage      Undeveloped
Acreage
       Gross      Net      Gross      Net
(thousands)                            

United States

     4,223      2,559      3,208      1,766

Canada

     731      471      577      483

Total

     4,954      3,030      3,785      2,249

 

Net Wells Drilled in the Calendar Year

The number of net wells completed during each of the last three years ending December 31 follows:

 

       2004      2003      2002

Exploratory:

                    

United States

                    

Productive

     7      8      12

Dry

     7      7      12

Total United States

     14      15      24

Canada

                    

Productive

     34      10      1

Dry

     7      1      1

Total Canada

     41      11      2

Total Exploratory

     55      26      26

Development:

                    

United States

                    

Productive

     921      819      774

Dry

     17      36      38

Total United States

     938      855      812

Canada

                    

Productive

     36      31      61

Dry

     3      10      11

Total Canada

     39      41      72

Total Development

     977      896      884

Total wells drilled (net):

     1,032      922      910

 

As of December 31, 2004, 133 gross (92 net) wells were in process of being drilled, including wells temporarily suspended.

 

Productive Wells

The number of productive gas and oil wells in which Dominion’s subsidiaries had an interest at December 31, 2004, follows:

 

       Gross      Net

Gas wells

             

United States

     24,698      16,457

Canada

     644      408

Total gas wells

     25,342      16,865

Oil wells

             

United States

     1,004      517

Canada

     426      163

Total oil wells

     1,430      680

 

The number of productive wells includes 297 gross (117 net) multiple completion gas wells and 29 gross (12 net) multiple completion oil wells. Wells with multiple completions are counted only once for productive well count purposes.

 

Dominion’s Power Generation

Dominion Generation provides electricity for use on a wholesale and a retail level. Dominion Generation can supply electricity demand either from its generation facilities in Connecticut, Indiana, Illinois, Massachusetts, North Carolina, Ohio, Pennsylvania, Rhode Island, Virginia and West Virginia or through purchased power contracts when needed. The following table lists Dominion’s generating units and capability, including the generating plants acquired from USGen effective January 1, 2005.

 

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Dominion’s Power Generation

 

Plant      Location      Primary Fuel
Type
     Net Summer
Capability (Mw)
 

Utility Generation

                      

North Anna

     Mineral, VA      Nuclear      1,628 (a)

Surry

     Surry, VA      Nuclear      1,598  

Mt. Storm

     Mt. Storm, WV      Coal      1,569  

Chesterfield

     Chester, VA      Coal      1,234  

Chesapeake

     Chesapeake, VA      Coal      595  

Clover

     Clover, VA      Coal      441 (b)

Yorktown

     Yorktown, VA      Coal      326  

Bremo

     Bremo Bluff, VA      Coal      227  

Mecklenburg

     Clarksville, VA      Coal      138  

North Branch

     Bayard, WV      Coal      74  

Altavista

     Altavista, VA      Coal      63  

Southampton

     Southampton, VA      Coal      63  

Yorktown

     Yorktown, VA      Oil      818  

Possum Point

     Dumfries, VA      Oil      786  

Gravel Neck (CT)

     Surry, VA      Oil      183  

Darbytown (CT)

     Richmond, VA      Oil      144  

Chesapeake (CT)

     Chesapeake, VA      Oil      144  

Possum Point (CT)

     Dumfries, VA      Oil      78  

Northern Neck (CT)

     Lively, VA      Oil      64  

Low Moor (CT)

     Covington, VA      Oil      60  

Kitty Hawk (CT)

     Kitty Hawk, NC      Oil      44  

Remington (CT)

     Remington, VA      Gas      580  

Possum Point (CC)

     Dumfries, VA      Gas      545 (c)

Chesterfield (CC)

     Chester, VA      Gas      397  

Possum Point

     Dumfries, VA      Gas      322  

Elizabeth River (CT)

     Chesapeake, VA      Gas      312  

Ladysmith (CT)

     Ladysmith, VA      Gas      290  

Bellmeade (CC)

     Richmond, VA      Gas      230  

Gordonsville Energy (CC)

     Gordonsville, VA      Gas      217  

Gravel Neck (CT)

     Surry, VA      Gas      146  

Darbytown (CT)

     Richmond, VA      Gas      144  

Bath County

     Warm Springs, VA      Hydro      1,477 (d)

Gaston

     Roanoke Rapids, NC      Hydro      225  

Roanoke Rapids

     Roanoke Rapids, NC      Hydro      99  

Pittsylvania

     Hurt, VA      Other      80  

Other

     Various      Various      15  
                     15,356 (e)

Non-utility Generation

                      

Millstone

     Waterford, CT      Nuclear      1,953 (f)

Kincaid

     Kincaid, IL      Coal      1,158  

Brayton Point

     Somerset, MA      Coal      1,078 (g)

State Line

     Hammond, IN      Coal      515  

Salem Harbor

     Salem, MA      Coal      312 (g)

Morgantown

     Morgantown, WV      Coal      25 (h)

Brayton Point

     Somerset, MA      Oil      435 (g)

Salem Harbor

     Salem, MA      Oil      431 (g)

Fairless (CC)

     Fairless Hills, PA      Gas      1,096 (c)

Elwood (CT)

     Elwood, IL      Gas      704 (i)

Armstrong (CT)

     Shelocta, PA      Gas      625 (c)

Troy (CT)

     Luckey, OH      Gas      600 (c)

Manchester (CC)

     Providence, RI      Gas      426 (g)

Pleasants (CT)

     St. Mary’s, WV      Gas      313 (c)

Other

     Various      Various      38  
                     9,709  

Purchased Capacity

                   3,081 (j)
              Total Capacity      28,146  
Note:   (CT) denotes combustion turbine and (CC) denotes combined cycle
(a)   Excludes 11.6 percent undivided interest owned by Old Dominion Electric Cooperative (ODEC).
(b)   Excludes 50 percent undivided interest owned by ODEC.
(c)   Includes generating units which Dominion operates under leasing arrangements.
(d)   Excludes 40 percent undivided interest owned by Allegheny Generating Company, a subsidiary of Allegheny Energy, Inc.
(e)   Totals may not add due to rounding.
(f)   Excludes 6.53 percent undivided interest in Unit 3 owned by Massachusetts Municipal Wholesale Electric Company and Central Vermont Public Service Company.
(g)   Acquired January 1, 2005 from USGen New England, Inc. The Brayton Point Station also has four small generation units fired by oil-diesel (combined capacity 8 Mw) included in Non-Utility Generation-Other.
(h)   Excludes 50 percent partnership interest owned by Cogen Technologies Morgantown, Ltd. and Hickory Power Corporation.
(i)   Excludes 50 percent partnership interest owned by Peoples Energy.
(j)   Purchase capacity includes generation from the Batesville facility. Dominion has decided to divest its interest in the long-term power tolling contract associated with this facility. See Long-Term Power Tolling Contract in MD&A for additional information.

 

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Item 3. Legal Proceedings

From time to time, Dominion and its subsidiaries 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 Dominion and its subsidiaries, 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, Dominion and its subsidiaries are involved in various legal proceedings. Management believes that the ultimate resolution of these proceedings will not have a material adverse effect on Dominion’s financial position, liquidity or results of operations.

See Regulation in Item 1. Business, Future Issues and Other Matters in MD&A, and Note 22 to the Consolidated Financial Statements for additional information on rate matters and various regulatory proceedings to which Dominion is a party.

Before being acquired by Dominion, Louis Dreyfus Natural Gas Corp. (Louis Dreyfus) was one of numerous defendants in a lawsuit consolidated and now pending in the 93rd Judicial District Court in Hidalgo County, Texas. The lawsuit alleges that gas wells and related pipeline facilities operated by Louis Dreyfus, and other facilities operated by other defendants, caused an underground hydrocarbon plume in McAllen, Texas. The plaintiffs claim that they have suffered damages, including property damage and lost profits, as a result of the alleged plume and seek compensation for these items.

In July 1997, Jack Grynberg, an oil and gas entrepreneur, brought suit against CNG and several of its subsidiaries. The suit seeks damages for alleged fraudulent mismeasurement of gas volumes and underreporting of gas royalties from gas production taken from federal leases. The suit was consolidated with approximately 360 other cases in the U.S. District Court for the District of Wyoming. Parts of Mr. Grynberg’s claims were dismissed on the basis that they overlapped with Mr. Wright’s claims, which are noted below. Mr. Grynberg has filed an appeal. The defendants have filed a motion to dismiss.

In April 1998, Harrold E. (Gene) Wright, an oil and gas entrepreneur, brought suit against Dominion Exploration & Production, Inc. (formerly known as CNG Producing Company), a subsidiary of CNG, alleging various fraudulent valuation practices in the payment of royalties on federal leases. Shortly after filing, this case was consolidated under the Federal Multidistrict Litigation rules with the Grynberg case noted above. A substantial portion of the claim against CNG Producing Company was resolved by settlement in late 2002. The case was remanded back to the U.S. District Court for the Eastern District of Texas, which denied the defendant’s motion to dismiss on jurisdictional grounds in January 2005. Discovery may begin in the matter in the spring of 2005.

In August 2004, DTI received a proposed Consent Order and Agreement (COA) from the Pennsylvania Department of Environmental Protection (PADEP) which would supersede a 1990 COA between the parties. The proposed COA would resolve groundwater contamination issues at several DTI compressor stations in Pennsylvania. The draft COA proposes penalties to be paid to PADEP and the Pennsylvania Department of Conservation and Natural Resources to resolve alleged violations. The proposed COA has not been accepted by DTI and is subject to ongoing negotiations with the agencies. Management believes that the ultimate resolution of the COA will not have a material effect on Dominion.

 

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

None.

 

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Executive Officers of the Registrant

 

Name and Age      Business Experience Past Five Years

Thos. E. Capps (69)

     Chairman of the Board of Directors and Chief Executive Officer of Dominion from August 2000 to date; Chairman of the Board of Directors of Virginia Electric and Power Company from September 1997 to date; Chairman of the Board of Directors and Chief Executive Officer of Consolidated Natural Gas Company from January 2004 to date; President of Dominion from August 2000 to December 2003; Chief Executive Officer and President of Consolidated Natural Gas Company from January 2000 to December 2003; Vice Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from January 2000 to August 2000; Chairman of the Board of Directors, President and Chief Executive Officer of Dominion from September 1995 to January 2000.

Thomas F. Farrell, II (50)

     President and Chief Operating Officer of Dominion from January 2004 to date; President and Chief Operating Officer of Consolidated Natural Gas Company from January 2004 to date; Executive Vice President of Dominion from March 1999 to December 2003; President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to December 2003; Executive Vice President of Consolidated Natural Gas Company from January 2000 to December 2003; Chief Executive Officer of Virginia Electric and Power Company from May 1999 to December 2002.

Thomas N. Chewning (59)

     Executive Vice President and Chief Financial Officer of Dominion from May 1999 to date; Executive Vice President and Chief Financial Officer of Consolidated Natural Gas Company from January 2000 to date.

Jay L. Johnson (58)

     Executive Vice President of Dominion and President and Chief Executive Officer of Virginia Electric and Power Company from December 2002 to date; Senior Vice President, Business Excellence, Dominion Energy, Inc. from September 2000 to December 2002; Chief of Naval Operations, U.S. Navy, and member of the Joint Chiefs of Staff from 1996 until July 2000.

Duane C. Radtke (56)

     Executive Vice President of Dominion and Consolidated Natural Gas Company from April 2001 to date; President of Devon Energy International from August 2000 to April 2001; Executive Vice President—Production of Santa Fe Snyder Corp. from May 1999 to August 2000.

Mary C. Doswell (46)

     Senior Vice President and Chief Administrative Officer of Dominion from January 2003 to date; President and Chief Executive Officer of Dominion Resources Services, Inc. from January 2004 to date; President of Dominion Resources Services, Inc. from January 2003 to December 2003; Vice President—Billing and Credit of Virginia Electric and Power Company from October 2001 to December 2002; Vice President—Metering of Virginia Electric and Power Company from January 2000 to October 2001.

Paul D. Koonce (45)

     Chief Executive Officer—Energy of Virginia Electric and Power Company from January 2004 to date; Chief Executive Officer—Transmission of Virginia Electric and Power Company from January 2003 to December 2003; Senior Vice President—Portfolio Management of Virginia Electric and Power Company from January 2000 to December 2002.

Mark F. McGettrick (47)

     President and Chief Executive Officer—Generation of Virginia Electric and Power Company from January 2003 to date; Senior Vice President and Chief Administrative Officer of Dominion from January 2002 to December 2002; President of Dominion Resources Services, Inc. from October 2002 to January 2003; Senior Vice President—Customer Service and Metering of Virginia Electric and Power Company from January 2000 to December 2001.

Eva S. Hardy (60)

     Senior Vice President—External Affairs & Corporate Communications of Dominion from May 1999 to date; Senior Vice President-External Affairs & Corporate Communications of Virginia Electric and Power Company from September 1997 to April 2000.

G. Scott Hetzer (48)

     Senior Vice President and Treasurer of Dominion from May 1999 to date; Senior Vice President and Treasurer of Virginia Electric and Power Company and Consolidated Natural Gas Company from January 2000 to date.

James L. Sanderlin (63)

     Senior Vice President—Law of Dominion from September 1999 to date; Senior Vice President—Law of Consolidated Natural Gas Company from January 2000 to date.

Steven A. Rogers (43)

     Vice President, Controller and Principal Accounting Officer of Dominion and Consolidated Natural Gas Company and Vice President and Principal Accounting Officer of Virginia Electric and Power Company from June 2000 to date; Controller of Virginia Electric and Power Company from January 2000 to May 2000; Controller of Dominion Energy, Inc. from September 1998 to June 2000.

 

Any service listed for Virginia Electric and Power Company, Consolidated Natural Gas Company, Dominion Resources Services, Inc. and Dominion Energy, Inc. reflects service at a subsidiary of Dominion.

In May 2004, Dominion sold its telecommunications subsidiary, Dominion Telecom, Inc., to a third party and Dominion Telecom, Inc. became Elantic Telecom, Inc. Subsequent to the sale, Elantic Telecom, Inc. filed for protection under Chapter 11 of the U.S. Federal Bankruptcy code. Messrs. Johnson and Hetzer served as executive officers of Dominion Telecom, Inc. during the two years prior to its sale.

 

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Part II

 

Item 5. Market for the Registrant’s Common Equity and Related Stockholder Matters

Dominion’s common stock is listed on the New York Stock Exchange. At December 31, 2004, there were approximately 170,000 registered shareholders, including approximately 79,000 certificate holders. The quarterly information concerning stock prices and dividends is incorporated by reference from Note 29 to the Consolidated Financial Statements. Restrictions on the payment of dividends by Dominion are discussed in Note 20 to the Consolidated Financial Statements.

During 2004, Dominion issued 111 shares of common stock to a former employee as a deferred payment under a 1985 performance achievement plan. These shares were not registered under the Securities Act of 1933 (Securities Act). The issuance of this stock did not involve a public offering, and is therefore exempt from registration under the Securities Act.

The following table presents registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock during the fourth quarter of 2004.

 

Issuer Purchases of Equity Securities
Period     

(a)

Total
Number of
Shares
(or Units)
Purchased (1)

    

(b)

Average
Price
Paid per
Share
(or Unit)

    

(c)

Total Number
of Shares (or Units)
Purchased as Part
of Publicly Announced
Plans or Programs

    

(d)

Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that May
Yet Be Purchased under the
Plans or Program

10/1/04 – 10/31/04

                 N/A      N/A

11/1/04 – 11/30/04

                 N/A      N/A

12/1/04 – 12/31/04

     84      $ 66.41      N/A      N/A

Total

     84      $ 66.41      N/A      N/A

 

(1)   Amounts are registered shares tendered by employees to satisfy tax withholding obligations on vested restricted stock.

 

Item 6. Selected Financial Data

 

       2004(1)        2003(2)        2002      2001(3)      2000(4)
(millions, except per share amounts)                                       

Operating revenue

     $ 13,972        $ 12,078        $ 10,218      $ 10,558      $ 9,246

Income from continuing operations before cumulative effect of changes in accounting principles

       1,264          949          1,362        544        415

Loss from discontinued operations, net of taxes(5)

       (15 )        (642 )                     

Cumulative effect of changes in accounting principles, net of taxes

                11                        21

Net income

       1,249          318          1,362        544        436

Income from continuing operations before cumulative effect of changes in accounting principles per common share—basic

       3.84          2.99          4.85        2.17        1.76

Net income per common share—basic

       3.80          1.00          4.85        2.17        1.85

Income from continuing operations before cumulative effect of changes in accounting principles per common share—diluted

       3.82          2.98          4.82        2.15        1.76

Net income per common share—diluted

       3.78          1.00          4.82        2.15        1.85

Dividends paid per share

       2.60          2.58          2.58        2.58        2.58

Total assets

       45,446          43,546          39,239        36,044        30,449

Long-term debt(6)

       15,507          15,776          12,060        12,119        10,101

Preferred securities of subsidiary trusts(6)

                         1,397        1,132        385

 

(1)   Dominion’s 2004 results include a $112 million after-tax charge reflecting Dominion’s valuation of its interest in a long-term power tolling contract and $61 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges.
(2)   Dominion’s 2003 results include $122 million of after-tax incremental restoration expenses associated with Hurricane Isabel. Also in 2003, Dominion adopted accounting standards that resulted in the recognition of the cumulative effect of changes in accounting principles. See Note 3 to the Consolidated Financial Statements.
(3)   Dominion’s 2001 results include a $97 million after-tax charge representing exposure to the Enron Corp. bankrupcty and $68 million of after-tax charges associated with a senior management restructuring initiative.
(4)   Dominion’s 2000 results include $198 million of after-tax restructuring and other acquisition-related costs resulting from the merger with Consolidated Natural Gas Company.
(5)   Reflects the net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004. See Note 9 to the Consolidated Financial Statements.
(6)   Upon adoption of Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, on December 31, 2003 with respect to special purpose entities, Dominion began reporting as long-term debt its junior subordinated notes held by five capital trusts, rather than the trust preferred securities issued by those trusts. See Note 3 to the Consolidated Financial Statements.

 

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) discusses the results of operations and general financial condition of Dominion. MD&A should be read in conjunction with the Consolidated Financial Statements. The term “Dominion” is used throughout MD&A and, depending on the context of its use, may represent any of the following: the legal entity, Dominion Resources, Inc.; one of Dominion Resources, Inc.’s consolidated subsidiaries; or the entirety of Dominion Resources, Inc. and its consolidated subsidiaries.

 

Contents of MD&A

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

  Forward-Looking Statements
  Introduction
  Accounting Matters
  Results of Operations
  Segment Results of Operations
  Selected Information—Energy Trading Activities
  Sources and Uses of Cash
  Future Issues and Other Matters
  Market Rate Sensitive Instruments and Risk Management
  Risk Factors and Cautionary Statements that May Affect Future Results

 

Forward-Looking Statements

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

Dominion makes 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 risks that may cause actual results to differ from predicted results are set forth in Risk Factors and Cautionary Statements That May Affect Future Results.

Dominion bases its forward-looking statements on management’s beliefs and assumptions using information available at the time the statements are made. Dominion cautions the reader not to place undue reliance on its forward-looking statements because the assumptions, beliefs, expectations and projections about future events may, and often do, differ materially from actual results. Dominion undertakes no obligation to update any forward-looking statement to reflect developments occurring after the statement is made.

 

Introduction

Dominion is a diversified, fully integrated electric and gas holding company headquartered in Richmond, Virginia. Dominion concentrates its efforts largely in what Dominion refers to as the “MAIN to Maine” region. In the power industry, “MAIN” means the Mid-America Interconnected Network, which comprises all of Illinois and portions of the states of Missouri, Iowa, Wisconsin, Michigan and Minnesota. Under this strategy, Dominion focuses its efforts on the region stretching from MAIN, through its primary Mid-Atlantic service areas in Ohio, Pennsylvania, West Virginia, Virginia and North Carolina, and up through New York and New England. The MAIN-to-Maine region is home to approximately 40% of the nation’s demand for energy.

Operating in all aspects of the energy supply chain allows Dominion to optimize the value of its energy portfolio and enhance its return on invested capital. Dominion has the capability to discover and produce gas, store it, sell it or use it to generate power; it can generate electricity to sell to customers in its retail markets or in wholesale transactions. These capabilities give Dominion the ability to produce and sell energy in whatever form it finds most useful and economic. Dominion also operates North America’s largest natural gas storage system, which gives it the flexibility to provide supply when it is most economically advantageous to do so.

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

Dominion Generation includes the generation operations of Dominion’s electric utility and merchant fleet. The generation mix is diversified and includes coal, nuclear, gas, oil, hydro and purchased power. Dominion’s strategy for its electric generation operations focuses on serving customers in the MAIN to Maine region. Its generation facilities are located in Virginia, West Virginia, North Carolina, Connecticut, Illinois, Indiana, Pennsylvania and Ohio. In addition, Dominion completed the acquisition of three USGen New England Inc. (USGen) power stations located in Massachusetts and Rhode Island during January 2005 and expects to complete the acquisition of the Kewaunee nuclear power plant located in northeastern Wisconsin in the first half of 2005.

Utility generation operations represent Dominion Generation’s primary source of revenue and cash flow. These operations are sensitive to external factors, primarily weather and fuel prices. Currently, revenue from utility operations largely reflects the capped rates charged to customers in Virginia, the majority of its utility customer base. Under Virginia’s current deregulation legislation, electric rates are capped through 2010. Under capped rates, changes in Dominion Generation’s operating costs, particularly with respect to fuel, relative to costs used to establish the capped rates, will impact Dominion’s earnings. Dominion Generation has reduced costs by terminating certain long-term power purchase agreements.

 

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Prices received for electricity generated by its merchant fleet are market-based, subjecting Dominion Generation to risks associated with recovering capital expenditures and absorbing variability in fuel costs. Generally, Dominion Generation manages these risks by entering into both short-term and long-term fixed-price sales and purchase contracts.

Variability in expenses for Dominion Generation relates primarily to the cost of fuel consumed, labor and benefits and the timing, duration and costs of scheduled and unscheduled outages.

As discussed in further detail below, as a result of the reorganization of the Dominion Energy Clearinghouse (Clearinghouse), Dominion Generation’s 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities performed by the Clearinghouse that were previously reported in the Dominion Energy segment.

Dominion Energy includes the following operations:

  A regulated interstate gas transmission pipeline and storage system, serving Dominion’s gas distribution businesses and other customers in the Midwest, the Mid-Atlantic states and the Northeast;
  A regulated electric transmission system principally located in Virginia and northeastern North Carolina;
  A liquefied natural gas (LNG) import and storage facility in Maryland;
  Certain gas production operations located in the Appalachian basin; and
  Clearinghouse, which is responsible for energy trading, marketing, hedging, arbitrage and gas aggregation activities.

Dominion Energy’s revenue and cash flows are derived from both regulated and nonregulated operations.

Revenue and cash flow provided by regulated electric and gas transmission operations and the LNG facility are based primarily on rates established by the Federal Energy Regulatory Commission (FERC). Variability in revenue and cash flow provided by these businesses results primarily from changes in rates and the demand for services. Variability in expenses relates largely to operating and maintenance expenditures, including decisions regarding use of resources for operations and maintenance or capital-related activities.

Revenue and cash flow for Dominion Energy’s nonregulated businesses are subject to variability associated with changes in commodity prices. Dominion Energy’s nonregulated businesses use physical and financial arrangements to hedge this price risk. Certain hedging and trading activities may require cash deposits to satisfy margin requirements. In addition, reported earnings for this segment reflect changes in the fair value of certain derivatives; these values may change significantly from period to period. Variability in expenses for these nonregulated businesses relates largely to labor and benefits and the costs of purchased commodities for resale and payments under financially-settled contracts.

During the fourth quarter of 2004, Dominion performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenues and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets, in order to better reflect the performance of the underlying assets. As a result of these changes, 2004 and 2003 results now reflect revenues and expenses associated with coal and emissions trading and marketing activities in the Dominion Generation segment.

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

Revenue and cash flow provided by electric and gas distribution operations are based primarily on rates established by state regulatory authorities and state law. Variability in Dominion Delivery’s revenue and cash flow relates largely to changes in volumes, which are primarily weather sensitive. For local gas distribution operations, revenue may vary based upon changes in levels of rate recovery for the cost of gas sold to customers. Such costs and recoveries generally offset and do not materially impact net income. Revenue from retail energy marketing operations may vary in connection with changes in weather and commodity prices as well as the acquisition and potential loss of customers.

Variability in expenses results from changes in the cost of purchased gas and routine maintenance and repairs (including labor and benefits as well as decisions regarding the use of resources for operations and maintenance or capital-related activities). For gas distribution operations, Dominion is permitted to seek recovery of the cost of gas sold to customers.

Dominion Exploration & Production includes Dominion’s gas and oil exploration, development and production operations. These operations are located in several major producing basins in the lower 48 states, including the outer continental shelf and deepwater areas of the Gulf of Mexico, and Western Canada.

Dominion Exploration & Production maintains an active and ongoing drilling program focused on low risk development drilling in several proven onshore regions of the United States and Western Canada, while also maintaining some exposure to higher risk exploration opportunities. Significant development drilling programs are currently underway in West Texas, the Appalachians and the Rocky Mountains where Dominion Exploration & Production holds sizable acreage positions and operational experience. While each region provides Dominion Exploration & Production with exploration opportunities, most exploratory drilling takes place in the Gulf Coast region, including the deepwater Gulf of Mexico.

 

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Revenue and cash flow provided by exploration and production operations are based primarily on the production and sale of company-owned natural gas and oil reserves. Variability in Dominion Exploration & Production’s revenue and cash flow relates primarily to changes in commodity prices, which are market based, and volumes, which are impacted by numerous factors including drilling success, timing of development projects, as well as external factors such as the storm-related damage caused by Hurricane Ivan. Dominion manages commodity price volatility by hedging a substantial portion of its near term expected production.

Variability in Dominion Exploration & Production’s expenses relates primarily to changes in operating costs and production taxes, which tend to increase or decrease with changes in gas and oil prices and the prevailing cost environment. Commodity price changes place upward or downward pressure on related exploration and production service industry costs, while severance and property taxes vary based on changes in revenue. A changing price environment impacts both operating costs and the cost of acquiring, finding and developing natural gas and oil reserves.

Corporate and Other includes:

  Dominion’s corporate, service company and other operations, including unallocated debt;
  The remaining assets of Dominion Capital, Inc. (DCI), a financial services subsidiary, which are being divested in accordance with a Securities and Exchange Commission (SEC) order;
  The net impact of Dominion’s discontinued telecommunications operations that were sold in May 2004; and
  Specific items attributable to Dominion’s operating segments that are reported in Corporate and Other.

 

Accounting Matters

Critical Accounting Policies and Estimates

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

 

Accounting for derivative contracts at fair value

Dominion uses derivative contracts (primarily forward purchases and sales, swaps, options and futures) to buy and sell energy-related commodities and to manage its commodity and financial markets risks. Derivative contracts, with certain exceptions, are subject to fair value accounting and are reported on the Consolidated Balance Sheets at fair value. Accounting requirements for derivatives and related hedging activities are complex and may be subject to further clarification by standard-setting bodies.

Fair value of derivatives is based on actively quoted market prices, if available. In the absence of actively quoted market prices, Dominion seeks indicative price information from external sources, including broker quotes and industry publications. If pricing information from external sources is not available, Dominion must estimate prices based on available historical and near-term future price information and use of statistical methods. For options and contracts with option-like characteristics where pricing information is not available from external sources, Dominion generally uses a modified Black-Scholes Model that considers time value, the volatility of the underlying commodities and other relevant assumptions. Dominion uses other option models when contracts involve different commodities or commodity locations and when contracts allow either the buyer or seller the ability to exercise within a range of quantities. For contracts with unique characteristics, Dominion estimates fair value using a discounted cash flow approach. If pricing information is not available from external sources, judgment is required to develop estimates of fair value. For individual contracts, the use of different valuation models or assumptions could have a material effect on the contract’s estimated fair value.

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

 

Use of estimates in goodwill impairment testing

As of December 31, 2004, Dominion reported $4.3 billion of goodwill on its Consolidated Balance Sheet, a significant portion of which resulted from the acquisition of CNG in 2000. Substantially all of this goodwill is allocated to Dominion’s Generation, Transmission, Delivery and Exploration & Production reporting units. In April of each year, Dominion tests its goodwill for potential impairment, and performs additional tests more frequently if impairment indicators are present. The 2004 annual test did not result in the recognition of any impairment of goodwill, as the estimated fair values of Dominion’s reporting units exceeded their respective carrying amounts. During the fourth quarter of 2004, Dominion tested $72 million of goodwill allocated to the Clearinghouse reporting unit after management decided to exit certain energy trading activities and change the focus of the business, which resulted in a reduction of the unit’s expected future cash flows. This interim test indicated that no impairment existed and approximately $8 million of the unit’s goodwill was reallocated to other reporting units as of December 31, 2004 in connection with management’s reorganization of that business. In 2003 and 2002, impairment charges of $78 million and $13 million, respectively, were recognized as a result of interim tests conducted for certain DCI subsidiaries and Dominion’s telecommunications business.

 

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Dominion estimates the fair value of its reporting units by using a combination of discounted cash flow analyses, based on its internal five-year strategic plan, and other valuation techniques that use multiples of earnings for peer group companies and analyses of recent business combinations involving peer group companies. These calculations are dependent on subjective factors such as management’s estimate of future cash flows, the selection of appropriate discount and growth rates, and the selection of peer group companies and recent transactions. These underlying assumptions and estimates are made as of a point in time; subsequent modifications, particularly changes in discount rates or growth rates inherent in management’s estimates of future cash flows, could result in a future impairment of goodwill. Although Dominion has consistently applied the same methods in developing the assumptions and estimates that underlie the fair value calculations, such as estimates of future cash flows, and based those estimates on relevant information available at the time, such cash flow estimates are highly uncertain by nature and may vary significantly from actual results. If the estimates of future cash flows used in the 2004 annual test had been 10% lower, the resulting fair values would have still been greater than the carrying values of each of those reporting units, indicating 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 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 management’s judgment in areas such as identifying circumstances indicating an impairment may exist, identifying and grouping affected assets and developing the undiscounted and discounted estimated future cash flows (used to estimate fair value in the absence of market-based value) associated with the asset, including the selection of an appropriate discount rate. Although cash flow estimates used by Dominion would be based on relevant information available at the time the estimates are made, estimates of future cash flows are, by nature, highly uncertain and may vary significantly from actual results. For example, estimates of future cash flows would contemplate factors such as the expected use of the asset, including future production and sales levels, and expected fluctuations of prices of commodities sold and consumed.

During 2004, Dominion did not test any significant long-lived assets or asset groups for impairment as no circumstances arose that indicated an impairment may exist. In 2003, reflecting a significant revision in long-term expectations for potential growth in telecommunications service revenue, Dominion approved a strategy to sell its interest in the telecommunications business. In connection with this change in strategy, Dominion tested the network assets to be sold for impairment, using the revised long-term expectations for potential growth. Dominion’s assets were determined to be substantially impaired and were written down to fair value. Dominion sold its telecommunications business in 2004.

 

Asset retirement obligations

Dominion recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These asset retirement obligations (AROs) are recognized at fair value as incurred, and are capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, Dominion estimates the fair value of its AROs using present value techniques, in which Dominion makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. AROs currently reported on Dominion’s Consolidated Balance Sheets were measured during a period of historically low interest rates. The impact on measurements of new AROs, using different rates in the future, may be significant. Dominion did not recognize any new, significant AROs in 2004. In the future, if Dominion revises any assumptions used to calculate the fair value of existing AROs, Dominion will adjust the carrying amount of both the ARO liability and related long-lived asset. Dominion records accretion expense, increasing the ARO liability, with the passage of time. In 2004 and 2003, Dominion recognized $91 million and $86 million, respectively, of accretion expense, and expects to incur $95 million in 2005.

A significant portion of Dominion’s AROs relate to the future decommissioning of its nuclear facilities. At December 31, 2004, nuclear decommissioning AROs, which are reported in the Dominion Generation segment, totaled $1.4 billion, representing approximately 82% of Dominion’s total AROs. Based on their significance, the following discussion of critical assumptions inherent in determining the fair value of AROs relates to those associated with Dominion’s nuclear decommissioning obligations.

Dominion obtains from third-party experts periodic site-specific “base year” cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for its utility nuclear plants. Dominion uses internal cost studies for its merchant nuclear facility based on similar methods. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these cost estimates are dependent on subjective factors, including the selection of cost escalation rates, which Dominion considers to be a critical assumption.

Dominion determines 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 its nuclear facilities. The weighted average cost escalation used by Dominion was 3.18%. The use of alternative rates would have been material to the liabilities recognized. For example, had Dominion increased the cost escalation rate by 0.5% to 3.68%, the amount recognized as of December 31, 2004 for its AROs related to nuclear decommissioning would have been $269 million higher.

 

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Employee benefit plans

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

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

  Historical return analysis to determine expected future risk premiums;
  Forward-looking return expectations derived from the yield on long-term bonds and the price earnings ratios of major stock market indices;
  Expected inflation and risk-free interest rate assumptions; and
  Investment allocation of plan assets. Dominion’s strategic target asset allocation for its pension fund is 45% U.S. equity securities, 8% non-U.S. equity securities, 22% debt securities and 25% other, such as real estate and private equity investments.

Assisted by an independent actuary, management develops assumptions, which are then compared to the forecasts of other independent investment advisors to ensure reasonableness. An internal committee selects the final assumptions. Dominion calculated its pension cost using an expected return on plan assets assumption of 8.75% for 2004 and 2003, compared to 9.5% for 2002. Dominion calculated its 2004 other postretirement benefit cost using an expected return on plan assets assumption of 7.79%, compared to 7.78% and 7.82% for 2003 and 2002, respectively. The rate used in calculating other postretirement benefit cost is lower than the rate used in calculating pension cost because of differences in the relative amounts of various types of investments held as plan assets and because other postretirement benefit activity, unlike the pension activity, is partially taxable.

Discount rates are determined from analyses performed by a third party actuarial firm of AA/Aa rated bonds with cash flows matching the expected payments to be made under Dominion’s plans. Due to declines in bond yields and interest rates, Dominion reduced the discount rate used to calculate 2004 pension and other postretirement benefit cost to 6.25% compared to the 6.75% and 7.25% discount rates that it used to calculate 2003 and 2002 pension and other postretirement benefit cost, respectively.

The medical cost trend rate assumption is established based on analyses performed by a third party actuarial firm of various factors including the specific provisions of Dominion’s medical plans, actual cost trends experienced and projected, and demographics of plan participants. Dominion’s medical cost trend rate assumption as of December 31, 2004 is 9% and is expected to gradually decrease to 5% in later years.

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

 

                     Increase in Net
Periodic Cost
Actuarial Assumption      Change in
Assumption
     Pension
Benefits
     Other
Postretirement
Benefits
              (millions)

Discount rate

     (0.25 )%    $ 13      $ 6

Rate of return on plan assets

     (0.25 )%      10        2

Healthcare cost trend rate

     1 %      N/A        22

 

In addition to the effects on cost, a 0.25% decrease in the discount rate would increase the projected pension benefit obligation by $122 million and would increase the accumulated postretirement benefit obligation by $45 million.

 

Accounting for regulated operations

Dominion’s accounting for its regulated electric and gas operations differs from the accounting for nonregulated operations in that Dominion is required to reflect the effect of rate regulation in its Consolidated Financial Statements. Specifically, Dominion’s regulated businesses record assets and liabilities that nonregulated companies would not report under accounting principles generally accepted in the United States of America. When it is probable that regulators will allow for the recovery of current costs through future rates charged to customers, Dominion defers these costs that otherwise would be expensed by nonregulated companies and recognizes regulatory assets in its financial statements. Likewise, Dominion recognizes regulatory liabilities in its financial statements when it is probable that regulators will require reductions in revenue associated with customer credits through future rates and when revenue is collected from customers for expenditures that are not yet incurred.

Management evaluates whether or not recovery of its regulatory assets through future regulated rates is probable and makes various assumptions in its analyses. The expectations of future recovery are generally based on orders issued by regulatory commissions or historical experience, as well as discussions with applicable regulatory authorities. If recovery of regulatory assets is determined to be less than probable, the regulatory asset will be written off and an expense will be recorded in the period such assessment is made. Management currently believes the recovery of its regulatory assets is probable. See Notes 2 and 14 to the Consolidated Financial Statements.

 

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Accounting for gas and oil operations

Dominion follows the full cost method of accounting for gas and oil exploration and production activities prescribed by the SEC. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized and subsequently depreciated using the units-of-production method. The depreciable 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 depreciable base are subject to a ceiling test prescribed by the SEC. The test limits capitalized amounts to a ceiling—the present value of estimated future net revenues to be derived from the production of proved gas and oil reserves assuming period-end pricing adjusted for cash flow hedges in place. Dominion performs the ceiling test quarterly, on a country-by-country basis, and would recognize asset impairments to the extent that total capitalized costs exceed the ceiling. In addition, gains or losses on the sale or other disposition of gas and oil properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of natural gas and oil attributable to a country.

Dominion’s estimate of proved reserves requires a large degree of judgment and is dependent on factors such as historical data, engineering estimates of proved reserve quantities, estimates of the amount and timing of future expenditures to develop the proved reserves, and estimates of future production from the proved reserves. Given the volatility of natural gas and oil prices, it is possible that Dominion’s estimate of discounted future net cash flows from proved natural gas and oil reserves that is used to calculate the ceiling could change in the near term.

The process to estimate reserves is imprecise, and estimates are subject to revision. In the last five years, revisions to Dominion’s estimates of proved developed and undeveloped reserves have averaged approximately 3% of the previous year’s estimate. If there is a significant variance in any of its estimates or assumptions in the future and revisions to the value of its proved reserves are necessary, related depletion expense and the calculation of the ceiling test would be affected and recognition of natural gas and oil property impairments could occur. See Notes 2 and 28 to the Consolidated Financial Statements.

 

Income Taxes

Judgment is required in developing Dominion’s provision for income taxes, including the determination of deferred tax assets and any related valuation allowance. Dominion evaluates the probability of realizing its deferred tax assets on a quarterly basis by reviewing its forecast of future taxable income and the availability of tax planning strategies that can be implemented, if necessary, to realize deferred tax assets. Failure to achieve forecasted taxable income or successfully implement tax planning strategies might affect the ultimate realization of deferred tax assets.

 

Newly Adopted Accounting Standards

During 2004 and 2003, Dominion was required to adopt several new accounting standards, the requirements of which are discussed in Notes 2 and 3 to the Consolidated Financial Statements. The accounting standards adopted during 2003 affect the comparability of Dominion’s Consolidated Statements of Income. The following discussion is presented to provide an understanding of the impacts of those standards on that comparability.

 

FIN 46R

The adoption of Financial Accounting Standards Board (FASB) Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, (FIN 46R) on December 31, 2003 with respect to special purpose entities, affected the comparability of Dominion’s 2004 Consolidated Statement of Income to prior years as follows:

  Dominion was required to consolidate certain variable interest lessor entities through which Dominion had financed and leased several new power generation projects, as well as its corporate headquarters and aircraft. As a result, the Consolidated Balance Sheet as of December 31, 2003 reflects an additional $644 million in net property, plant and equipment and deferred charges and $688 million of related debt. In 2004, Dominion’s Consolidated Statement of Income reflects depreciation expense on the net property, plant and equipment and interest expense on the debt associated with these entities, whereas in prior years it reflected as rent expense in other operations and maintenance expense, the lease payments to these entities.
  In addition, under FIN 46R, Dominion reports as long-term debt its junior subordinated notes held by five capital trusts, rather than the trust preferred securities issued by those trusts. As a result, in 2004 Dominion reported interest expense on the junior subordinated notes rather than preferred distribution expense on the trust preferred securities.

 

SFAS No. 143

Adopting Statement of Financial Accounting Standards (SFAS) No. 143, Accounting for Asset Retirement Obligations, on January 1, 2003, affected the comparability of Dominion’s 2004 and 2003 Consolidated Statements of Income to the prior year as follows:

  Accretion of the AROs, including nuclear decommissioning, is reported in other operations and maintenance expense. Previously, expenses associated with the provision for nuclear decommissioning were reported in depreciation expense and in other income (loss); and
  Realized and unrealized earnings of trusts available for funding decommissioning activities at Dominion’s utility nuclear plants are recorded in other income (loss) and AOCI, as appropriate. Previously, as permitted by regulatory authorities, these earnings, along with an offsetting charge to expense, for the accretion of the decommissioning liability, were both reported in other income (loss).

 

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EITF 02-3 and EITF 03-11

The adoption of Emerging Issues Task Force (EITF) Issue No. 02-3, Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities, and related EITF Issue No. 03-11, Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3, changed the timing of recognition in earnings for certain Clearinghouse energy-related contracts, as well as the financial statement presentation of gains and losses associated with energy-related contracts. The Consolidated Statement of Income for 2002 was not restated. Prior to 2003, all energy trading contracts, including non-derivative contracts, were recorded at fair value with changes in fair value and settlements reported in revenue on a net basis. Specifically, adopting EITF 02-3 and EITF 03-11 affected the comparability of Dominion’s 2004 and 2003 Consolidated Statements of Income to the prior year as follows:

  For derivative contracts not held for trading purposes that involve physical delivery of commodities, unrealized gains and losses and settlements on sales contracts are presented in revenue, while unrealized gains and losses and settlements on purchase contracts are reported in expenses; and
  Non-derivative energy-related contracts, previously subject to fair value accounting under prior accounting guidance, are recognized as revenue or expense on a gross basis at the time of contract performance, settlement or termination.

 

Other

Dominion enters into buy/sell and related agreements as a means to reposition its offshore Gulf of Mexico crude oil production to more liquid marketing locations onshore. Dominion typically enters into either a single or a series of buy/sell transactions in which it sells its crude oil production at the offshore field delivery point and buys similar quantities at Cushing, Oklahoma for sale to third parties. Dominion is able to enhance profitability by selling to a wide array of refiners and/or trading companies at Cushing, one of the largest crude oil markets in the world, versus restricting sales to a limited number of refinery purchasers in the Gulf of Mexico. These transactions require physical delivery of the crude oil and the risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling and counter party nonperformance risk.

Under the primary guidance of EITF Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent, Dominion presents the sales and purchases related to its crude oil buy/sell arrangements on a gross basis in its Consolidated Statements of Income. The EITF is currently discussing Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, which specifically focuses on purchase and sale transactions made pursuant to crude oil buy/sell arrangements. The EITF is evaluating whether these types of transactions should be presented net in the Consolidated Statements of Income. While resolution of this issue may affect the income statement presentation of these revenues and expenses, there would be no impact on Dominion’s results of operations or cash flows. The portion of Dominion’s operating revenue related to buy/sell activity for the years 2004, 2003, and 2002 was 2.1%, 1.5%, and 1.6% respectively. Reported production volumes are not impacted, as only the initial sale of Dominion’s production is included in reported production volumes. It is estimated that approximately 55% of Dominion’s 2004 oil production was marketed through the use of one or more crude oil buy/sell agreements. See Note 2 to the Consolidated Financial Statements.

 

Results of Operations

Presented below is a summary of contributions by operating segments to net income:

 

Year Ended December 31,      2004        2003        2002  
       Net
Income
       Diluted
EPS
       Net
Income
       Diluted
EPS
       Net
Income
       Diluted
EPS
 
(millions, except per share amounts)                                                      

Dominion Generation

     $ 525        $ 1.59        $ 512        $ 1.60        $ 561        $ 1.98  

Dominion Energy

       190          0.57          346          1.09          268          0.95  

Dominion Delivery

       466          1.41          453          1.42          422          1.49  

Dominion Exploration & Production

       595          1.80          415          1.30          380          1.34  

Primary operating segments

       1,776          5.37          1,726          5.41          1,631          5.76  

Corporate and Other

       (527 )        (1.59 )        (1,408 )        (4.41 )        (269 )        (0.94 )

Consolidated

     $ 1,249        $ 3.78        $ 318        $ 1.00        $ 1,362        $ 4.82  

 

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Overview

2004 vs. 2003

Dominion earned $3.78 per diluted share on net income of $1.2 billion, an increase of $2.78 per diluted share and $931 million. The per share amount includes approximately $0.14 of share dilution, reflecting an increase in the average number of common shares outstanding during 2004.

The combined net income contribution of Dominion’s primary operating segments increased $50 million during 2004. See Note 27 to the Consolidated Financial Statements for information about Dominion’s operating segments. The increase is primarily due to:

  A lower contribution from regulated electric generation operations primarily due to the elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. These higher fuel costs were partially offset by a reduction in capacity expenses due to the termination of certain long-term power purchase agreements and increased revenue due to favorable weather and customer growth;
  Net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net realized losses (including investment income) during the prior year;
  A loss from energy trading and marketing activities, reflecting comparatively lower price volatility on natural gas option positions and the effect of unfavorable price changes on electric trading margins, partially offset by favorable margins in coal trading and marketing;
  A higher contribution from nonregulated retail energy marketing operations, primarily reflecting an increase in average customer accounts and higher electric and gas margins; and
  A higher contribution from exploration and production operations due to favorable changes in the fair value of certain oil options, higher average realized prices for gas and oil and the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan. Results were also affected by the recognition of revenue in connection with deliveries under volumetric production payment (VPP) agreements, partially offset by lower gas production, reflecting the sale of mineral rights under the VPP agreements.

In addition to the higher contribution by the operating segments in 2004, the consolidated results include the impact of several specific items recognized in 2004 and reported in the Corporate and Other segment, including:

  A $112 million after-tax charge reflecting Dominion’s valuation of its interest in a long-term power tolling contract, which is subject to a planned divestiture in the first quarter of 2005, as a result of its exit from certain energy trading activities. The charge is based on Dominion’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of Dominion’s interest in the contract;
  $61 million of after-tax losses related to the discontinuance of hedge accounting for certain oil hedges resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter;
  $61 million of after-tax charges related to Dominion’s investment in and planned divestiture of DCI assets;
  $43 million of net after-tax charges resulting from the termination of certain long-term power purchase agreements;
  $13 million of after-tax losses associated with Dominion’s telecommunications business, which was sold during 2004; partially offset by
  A $28 million after-tax benefit associated with the disposition of CNG International’s (CNGI) investment in Australian pipeline assets that were sold during 2004.

Additionally, the improved consolidated results reflect the impact of significant specific items recognized in 2003. These items were reported in the Corporate and Other segment and are discussed in further detail below.

 

2003 vs. 2002

Dominion earned $1.00 per diluted share on net income of $318 million, a decrease of $3.82 per diluted share and $1.0 billion. The per share decrease includes approximately $0.13 of share dilution, reflecting an increase in the average number of common shares outstanding during 2003.

The combined net income contribution of Dominion’s primary operating segments increased $95 million in 2003. This increase largely reflects the benefits of higher natural gas prices during 2003 on sales of Dominion’s gas and oil production as well as margins associated with gas trading activities. This increased contribution by the operating segments was more than offset by significant specific charges recognized in 2003 and reported in the Corporate and Other segment, including:

  $750 million of after-tax losses associated with Dominion’s discontinued telecommunications business;
  $122 million of after-tax incremental expenses associated with Hurricane Isabel;
  $96 million of after-tax charges for DCI asset impairments;
  $69 million of after-tax charges for asset impairments related to certain investments held for sale;
  $104 million of after-tax charges associated with the termination of certain long-term power purchase agreements and the restructuring of power sales agreements; and
  $16 million of after-tax severance costs for workforce reductions.

 

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Analysis of Consolidated Operations

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

 

Year Ended December 31,      2004      2003      2002
(millions)                     

Operating Revenue

                          

Regulated electric sales

     $ 5,180      $ 4,876      $ 4,856

Regulated gas sales

       1,422        1,258        876

Nonregulated electric sales

       1,249        1,130        1,017

Nonregulated gas sales

       2,082        1,718        778

Gas transportation and storage

       802        740        705

Gas and oil production

       1,636        1,503        1,334

Other

       1,601        853        652

Operating Expenses

                          

Electric fuel and energy purchases, net

       2,162        1,667        1,447

Purchased electric capacity

       587        607        691

Purchased gas, net

       2,927        2,175        1,159

Liquids, pipeline capacity and other purchases

       1,007        468        159

Other operations and maintenance

       2,748        2,908        2,190

Depreciation, depletion and amortization

       1,305        1,216        1,258

Other taxes

       519        476        429

Other income (loss)

       186        (40 )      103

Interest and related charges

       939        975        945

Income tax expense

       700        597        681

Loss from discontinued operations, net of taxes

       (15 )      (642 )     

Cumulative effect of changes in accounting principles, net of taxes

              11       

An analysis of Dominion’s results of operations for 2004 compared to 2003 and 2003 compared to 2002 follows.

 

2004 vs. 2003

Operating Revenue

Regulated electric sales revenue increased 6% to $5.2 billion, primarily reflecting:

  A $231 million increase due to the impact of a comparatively higher fuel rate on increased sales volumes. The rate increase resulted from the settlement of a fuel rate case in December 2003. This increase in regulated electric sales revenue was more than offset by an increase in Electric fuel and energy purchases, net expense;
  A $24 million increase associated with favorable weather;
  A $49 million increase from customer growth associated with new customer connections; and
  An $18 million increase due to lost revenue in 2003 as a result of outages caused by Hurricane Isabel.

Regulated gas sales revenue increased 13% to $1.4 billion, largely resulting from a $198 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices and a $20 million increase resulting from the return of customers from Energy Choice programs, partially offset by an $87 million decrease associated with milder weather and lower industrial sales. The effect of this net increase in regulated gas sales revenue was largely offset by a comparable increase in Purchased gas, net expense.

Nonregulated electric sales revenue increased 11% to $1.2 billion, primarily reflecting the combined effects of:

  A $181 million increase in revenue from nonregulated retail energy marketing operations reflecting increased volumes ($165 million) and higher prices ($16 million);
  A $97 million increase in revenue from merchant generation operations, largely due to the commencement of commercial operations at the 1,096 megawatt Fairless Energy power station (Fairless) in June 2004, partially offset by decreased revenue at certain other stations resulting from lower generation volumes;
  A $140 million decrease in revenue from energy trading and marketing activities reflecting decreased margins in electric trading due to unfavorable price movements; and
  A $19 million decrease due to the sale of CNGI’s generation assets in December 2003.

Nonregulated gas sales revenue increased 21% to $2.1 billion, predominantly due to:

  A $279 million increase in revenue from producer services operations, reflecting higher prices ($157 million) and increased volumes ($122 million). This increase in nonregulated gas sales revenue was largely offset by a corresponding increase in Purchased gas, net expense;
  A $131 million increase in revenue from nonregulated retail energy marketing operations, reflecting increased volumes ($55 million) and higher prices ($76 million);
  A $61 million increase in revenue from sales of gas purchased by exploration and production operations to facilitate gas transportation and satisfy other agreements. This increase in nonregulated gas sales revenue was largely offset by a corresponding increase in Purchased gas, net expense; partially offset by
  A $108 million decrease in revenue from energy trading and marketing activities due to comparatively lower price volatility on natural gas option positions.

 

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Gas transportation and storage revenue increased 8% to $802 million, primarily reflecting:

  A $29 million increase due to the August 2003 reactivation of the Cove Point LNG facility, which was acquired by Dominion in September 2002; and
  A $27 million increase in revenue from gas transmission operations primarily reflecting increased transportation, storage, gathering and extraction revenues.

Gas and oil production revenue increased 9% to $1.6 billion as a result of:

  A $37 million increase in revenue from oil production, largely reflecting higher volumes; and
  A $180 million increase in revenue recognized related to deliveries under VPP transactions; partially offset by
  A $72 million decrease in revenue from gas production, primarily reflecting the sale of mineral rights under the VPP agreements.

Other revenue increased 88% to $1.6 billion, largely due to:

  A $384 million increase in coal sales revenue resulting from higher coal prices and increased sales volumes;
  A $120 million increase in sales of emissions credits reflecting higher prices and increased sales volumes; and
  A $109 million increase in revenue from sales of purchased oil by exploration and production operations.

These increases in other revenue were largely offset by corresponding increases in Liquids, pipeline capacity and other purchases expense. Other revenue for 2004 also includes $100 million from the recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan.

 

Operating Expenses and Other Items

Electric fuel and energy purchases, net expense increased 30% to $2.2 billion, primarily reflecting:

  A $408 million increase related to regulated utility operations resulting from the combined effects of an increase in the fixed fuel rate and the elimination of fuel deferral accounting for the Virginia jurisdiction, which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. The increase also reflects higher generation volumes in the current year;
  A $162 million increase related to nonregulated retail energy marketing operations reflecting increased volumes ($153 million) and higher prices ($9 million);
  An $88 million increase related to merchant generation operations, largely due to the commencement of commercial operations at Fairless, partially offset by decreased fuel expense at certain other stations resulting from lower generation volumes; partially offset by
  A $163 million decrease related to energy trading and marketing activities.

Purchased gas, net expense increased 35% to $2.9 billion, principally resulting from:

  A $274 million increase associated with producer services operations, reflecting higher prices ($159 million) and increased volumes ($115 million), as discussed above in Nonregulated gas sales revenue;
  A $130 million increase associated with regulated gas sales discussed above in Regulated gas sales revenue;  
  An $83 million increase associated with nonregulated retail energy marketing operations, reflecting increased volumes ($56 million) and higher prices ($27 million);
  A $66 million increase from gas transmission operations due to increased gathering and extraction activities and higher gas usage; and
  A $58 million increase related to purchases of gas by exploration and production operations to facilitate gas transportation and satisfy other agreements, as discussed above in Nonregulated gas sales revenue.

Liquids, pipeline capacity and other purchases expense increased 115% to $1.0 billion, primarily reflecting a $348 million increase in the cost of coal purchased for resale, a $105 million increase in emission credits purchased and a $108 million increase related to purchases of oil by exploration and production operations, each of which are discussed in Other revenue.

Other operations and maintenance expense decreased 6% to $2.7 billion, resulting from:

  A $113 million net benefit due to favorable changes in the fair value of certain oil options related to exploration and production operations. During 2004, Dominion effectively settled certain oil options not designated as hedges by entering into offsetting option positions that had the effect of preserving approximately $120 million in mark-to-market gains attributable to favorable changes in time value; and
  The impact of the following charges recognized in 2003:
    $197 million of incremental restoration expenses associated with Hurricane Isabel;
    $108 million of charges from asset and goodwill impairments associated with DCI’s financial services operations;
    $105 million of charges associated with the termination of certain long-term power purchase agreements;
    A $64 million charge for the restructuring of certain electric sales contracts recorded as derivative assets;
    A $60 million goodwill impairment associated with the purchase of the remaining interest in the telecommunications joint venture, Dominion Fiber Ventures, LLC (DFV), held by another party;
    A $28 million charge related to severance costs for workforce reductions; and
    A $22 million impairment related to CNGI’s generation assets that were sold in December 2003.

These benefits were partially offset by the following charges and incremental expenses recognized in 2004:

  A $184 million charge related to the valuation of Dominion’s interest in a long-term power tolling contract;
  $96 million of losses related to the discontinuance of hedge accounting for certain oil hedges resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter;
  $72 million of charges associated with the impairment of retained interests from mortgage securitizations and venture capital and other equity investments held by DCI;
 

$71 million of net expenses associated with the termination of certain long-term power purchase agreements;

 

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  An approximate $60 million increase in costs related to gas and oil production activities;
  An $18 million increase in reliability expenses associated with utility operations primarily due to increased tree-trimming;
  A $13 million increase related to salaries, wages and benefits resulting from a $60 million increase in pension and medical benefits and a $46 million increase due to wage increases and other factors, partially offset by an $89 million decrease in incentive-based compensation expense due to failure to meet targeted earnings goals; and
  $10 million of expenses associated with the sale of natural gas and oil assets in British Columbia, Canada.

Depreciation, depletion and amortization expense (DD & A) increased 7% to $1.3 billion, largely due to incremental depreciation expense resulting from property additions, including those resulting from the consolidation of certain variable interest entities as a result of adopting FIN 46R at December 31, 2003.

Other taxes increased 9% to $519 million, primarily due to higher gross receipts taxes and higher severance and property taxes associated with increased commodity prices.

Other income increased to $186 million from a net loss of $40 million, primarily reflecting:

  A $61 million increase resulting from net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net realized losses (including investment income) during the prior year;
  A $23 million benefit associated with the disposition of CNGI’s investment in Australian pipeline assets that were sold during 2004; and
  The impact of the following charges recognized in 2003, which did not recur in 2004:
    $57 million of costs associated with the acquisition of DFV senior notes;
    $27 million for the reallocation of equity losses between Dominion and the minority interest owner of DFV; and
    A $62 million impairment of CNGI’s investment in Australian pipeline assets held for sale.

Income taxes—Dominion’s effective tax rate decreased 3.0% to 35.6% for 2004, reflecting an increase in the valuation allowance for 2003 with no comparable increase in 2004, partially offset by increases in 2004 in utility plant differences and other factors.

Loss from discontinued operations decreased to $15 million from $642 million, primarily reflecting the sale of Dominion’s discontinued telecommunications operations during May 2004 and the impact of the following charges recognized in 2003:

  Impairment of network assets and related inventories of $566 million. Dominion did not recognize any deferred tax benefits related to the impairment charges, since realization of tax benefits is not anticipated at this time based on Dominion’s expected future tax profile. In addition, Dominion increased the valuation allowance on deferred tax assets recognized by its telecommunications investment, resulting in a $48 million increase in deferred income tax expense; and
  Telecommunications operating losses of $28 million.

2003 vs. 2002

Operating Revenue

Regulated electric sales revenue increased less than 1% to $4.9 billion, primarily reflecting the combined effects of:

  A $54 million increase from customer growth associated with new customer connections;
  A $42 million increase from higher fuel rate recoveries. Fuel rate recoveries were generally offset by a comparable increase in fuel expense and did not materially affect net income; and
  A $103 million decrease associated with milder weather.

Regulated gas sales revenue increased 44% to $1.3 billion, primarily due to the combined impact of a $289 million increase due to higher rates for regulated gas distribution operations primarily related to the recovery of higher gas prices and a $79 million increase associated with comparably colder weather in the first and fourth quarters of 2003. The effect of this net increase in regulated gas sales revenue was largely offset by a comparable increase in Purchased gas, net expense.

Nonregulated electric sales revenue increased 11% to $1.1 billion, primarily reflecting the combined effects of:

  A $77 million increase in revenue from merchant generation operations, reflecting higher volumes ($59 million) and higher prices ($18 million). The increase in volumes can be attributed to fewer outage days at the Millstone Power Station in 2003 and a full year’s sales from generating units placed into service during 2002;
  A $76 million increase in revenue from nonregulated retail energy marketing operations, primarily as a result of customer growth, including the acquisition of new customers previously served by other energy companies during 2003; and
  A $43 million decrease in revenue from energy trading and marketing activities due to unfavorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3, partially offset by increased margins.

Nonregulated gas sales revenue increased 121% to $1.7 billion, primarily reflecting:

  An $82 million increase in revenue from retail energy marketing operations, reflecting higher prices ($78 million) and higher volumes ($4 million);
  A $659 million increase in revenue from producer services operations, reflecting higher prices ($467 million) and higher volumes ($192 million); and
  A $208 million increase in revenue from energy trading and marketing activities due to higher margins, favorable changes in the fair value of derivative contracts held for trading purposes and the impact of adopting EITF 02-3.

Gas and oil production revenue increased 13% to $1.5 billion primarily due to higher average realized prices for gas and oil. It also includes $43 million of revenue recognized related to deliveries under a volumetric production payment transaction.

Other revenue increased 31% to $853 million, primarily reflecting the combined effects of:

  A $49 million increase in coal sales revenue;

 

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  A $115 million increase, resulting from a change in the classification of coal purchases from other revenue to expense under EITF 02-3 beginning in 2003;
  $94 million of emissions credit sales that began in 2003;
  A $26 million increase in sales of extracted products; and
  An $81 million decrease in revenue associated with Dominion financial services operations, reflecting the winding-down under Dominion’s divestiture strategy.

 

Operating Expenses and Other Items

Electric fuel and energy purchases expense increased 15% to $1.7 billion, primarily reflecting:

  A $154 million increase associated with energy trading and marketing activities and nonregulated retail energy marketing operations, primarily resulting from higher volumes purchased and the reclassification of certain purchase contracts due to the implementation of EITF 02-3; and
  A $68 million increase related to regulated utility operations, including $42 million associated with rate recovery in 2003 revenue and the recognition of $14 million of previously deferred fuel costs not recovered under the 2003 settlement of the Virginia jurisdictional fuel rate case.

Purchased electric capacity expense decreased 12% to $607 million, reflecting scheduled rate reductions on certain non-utility generation supply contracts ($54 million) and lower purchases of capacity for utility operations ($30 million), resulting from the termination of several long-term supply contracts.

Purchased gas expense increased 88% to $2.2 billion, primarily reflecting:

  A $647 million increase associated with producer services operations, reflecting higher prices ($459 million) and higher volumes ($188 million); and
  A $363 million increase associated with regulated gas operations discussed above in Regulated gas sales revenue.

Liquids, pipeline capacity and other purchases expense increased 194% to $468 million, reflecting primarily the reclassification of certain purchase contracts for transportation, storage, coal and emissions allowances due to the adoption of EITF 02-3.

Other operations and maintenance expense rose 33% to $2.9 billion, primarily reflecting the following specific items:

  $197 million of incremental restoration expenses associated with Hurricane Isabel;
  $108 million of asset and goodwill impairments associated with DCI’s financial services operations;
  $105 million of expenses associated with the termination of certain long-term power purchase contracts used in electric utility operations;
  A $64 million charge for the restructuring of certain electric sales contracts recorded as derivative assets;
  A $60 million goodwill impairment associated with the purchase of the remaining interest in the telecommunications joint venture held by another party;
  $86 million of accretion expense for AROs;
  An $87 million increase in expense resulting from a decrease in net pension credits and an increase in other postretirement benefit costs; partially offset by  
  A $15 million decrease in expenses associated with nuclear outages for refueling.

Other taxes increased 11% to $476 million, primarily due to higher severance taxes and gross receipts taxes, as well as the effect of a favorable resolution of sales and use tax issues in 2002. Such benefits were not recognized in 2003.

Other income decreased 138% to a net loss of $40 million, which included the following items:

  $57 million of costs associated with the acquisition of DFV senior notes;
  $27 million for the reallocation of equity losses between Dominion and the minority interest owner of DFV;
  $62 million for the impairment of certain equity-method investments; and
  A $32 million increase in net realized losses (including investment income) associated with nuclear decommissioning trust fund investments.

Partially offsetting these reductions to other income was an increase of $28 million, reflecting equity losses on Dominion’s investment in DFV in 2002; DFV was consolidated beginning in the first quarter of 2003. In 2003, the operating losses of DFV’s subsidiary, Dominion Telecom, Inc., were classified in discontinued operations.

Income taxes—Dominion’s effective tax rate increased 5.3% to 38.6% for 2003. The increase primarily resulted from the expiration of nonconventional fuel credits beginning in 2003, an increase in the valuation allowance related to the impairment of goodwill associated with the telecommunications investment and federal loss carryforwards at CNGI and DCI that are not expected to be utilized, partially offset by a reduction in Canadian tax rates applied to deferred tax balances.

Loss from discontinued operations reflects the results of operations of Dominion’s telecommunications business, which is classified as held for sale. The loss includes the following:

  Impairment of network assets and related inventories of $566 million. Dominion did not recognize any deferred tax benefits related to the impairment charges, since realization of tax benefits is not anticipated at this time based on Dominion’s expected future tax profile. In addition, Dominion increased the valuation allowance on deferred tax assets recognized by its telecommunications investment, resulting in a $48 million increase in deferred income tax expense; and
  Telecommunications operating losses of $28 million.

Cumulative effect of changes in accounting principles—During 2003 Dominion was required to adopt several new accounting standards, resulting in a net after-tax gain of $11 million which included the following:

  A $180 million after-tax gain (SFAS No. 143), partially offset by;
  A $67 million after-tax loss (EITF 02-3);
  A $75 million after-tax loss (Statement 133 Implementation Issue No. C20); and
  A $27 million after-tax loss (FIN 46R).

 

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Outlook—Dominion

Dominion believes its operating businesses will provide growth in net income on a per share basis, including the impact of higher expected average shares outstanding, in 2005.

Growth factors include:

  Continued growth in utility customers;
  Reduced electric capacity expenses, resulting from the termination of long-term power purchase agreements;
  Oil production growth, reflecting a full year of Devils Tower and Front Runner operations;
  A contribution from the operations of three USGen power stations acquired in January 2005;
  Higher contribution from Cove Point operations due to expansion of the facility; and
  A contribution from the Kewaunee nuclear power plant, expected to be acquired in the first half of 2005.

The growth factors will be partially offset by:

  Higher expected Virginia jurisdictional fuel expenses;
  A lower contribution from Millstone resulting from an additional refueling outage;
  Higher expected operating expenses for gas and oil production;
  An increase in incentive-based compensation expense if earnings targets are met; and
  Increased interest expense.

Based on these projections, Dominion estimates that cash flow from operations will increase in 2005, as compared to 2004. Management believes this increase will provide sufficient cash flow to maintain or grow Dominion’s current dividend to common shareholders.

 

Segment Results of Operations

Dominion Generation

Dominion Generation includes the generation operations of Dominion’s electric utility and merchant fleet as well as coal and emissions trading and marketing activities.

 

       2004      2003      2002
(millions, except EPS)                     

Net income contribution

     $ 525      $ 512      $ 561

EPS contribution

     $ 1.59      $ 1.60      $ 1.98

Electricity supplied (million mwhrs)

       112        105        101

 

mwhrs = megawatt hours

 

Presented below, on an after-tax basis, are the key factors impacting Dominion Generation’s operating results:

 

2004 vs. 2003

 

                Increase
(Decrease)
 
       Amount        EPS  
(millions, except EPS)                  

Fuel expenses in excess of rate recovery

     $ (115 )      $ (0.36 )

Regulated electric sales:

                     

Weather

       10          0.03  

Customer growth

       20          0.06  

Nuclear decommissioning trust performance

       38          0.12  

Coal trading and marketing

       31          0.10  

Capacity expenses

       36          0.11  

Other

       (7 )        (0.02 )

Share dilution

                (0.05 )

Change in net income contribution

     $ 13        $ (0.01 )

 

Dominion Generation’s net income contribution increased $13 million, primarily reflecting:

  Higher fuel expenses incurred by the regulated utility operations due to the elimination of fuel deferral accounting which resulted in the recognition of fuel expenses in excess of amounts recovered in fixed fuel rates. The increase in fuel expenses also reflects higher generation volumes;
  Higher regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting an increase in new residential customers, comparably favorable weather, lost revenue in 2003 due to outages associated with Hurricane Isabel, and the impact of the economy and other factors;
  Net realized gains (including investment income) associated with nuclear decommissioning trust fund investments as opposed to net realized losses (including investment income) during the prior year;
  A higher contribution from coal trading and marketing primarily due to higher coal prices and increased sales volumes; and
  Reduced purchased power capacity expenses due to the termination of long-term power purchase agreements in connection with the purchase of the related nonutility generating facilities.

 

2003 vs. 2002

 

                Increase
(Decrease)
 
       Amount        EPS  
(millions, except EPS)                  

Revenue reallocation

     $ (57 )      $ (0.20 )

Regulated electric sales:

                     

Weather

       (42 )        (0.15 )

Customer growth

       23          0.08  

Merchant generation margins

       18          0.06  

Capacity expenses

       29          0.10  

Fuel settlement

       (9 )        (0.03 )

Utility outages

       (13 )        (0.04 )

Other

       2          0.01  

Share dilution

                (0.21 )

Change in net income contribution

     $ (49 )      $ (0.38 )

 

Dominion Generation’s net income contribution decreased $49 million, primarily reflecting:

  A change in the allocation of electric utility base rate revenue beginning in 2003 among Dominion Generation, Dominion Energy and Dominion Delivery;
  A decrease in regulated electric sales due to comparably milder summer weather, resulting from a decrease in cooling degree days in 2003, partially offset by an increase in heating degree days in 2003;
  An increase in regulated electric sales due to customer growth in the electric franchise service area, primarily reflecting an increase in new residential customers;
  A higher contribution from merchant generation operations due to fewer outage days at the Millstone Power Station in 2003 and a full year’s contribution from gas-fired generating units placed into service during 2002;
  Scheduled decreases in capacity expenses under certain power purchase agreements;
  Recognition of previously deferred fuel costs in connection with the 2003 Virginia fuel rate settlement; and
  Increased utility outage expenses, reflecting the refueling activities at nuclear facilities in 2003.

 

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Dominion Energy

Dominion Energy includes Dominion’s electric transmission, natural gas transmission pipeline and storage businesses, an LNG facility, certain natural gas production, energy trading and marketing operations and producer services which includes aggregation of gas supply and related wholesale activities.

 

       2004      2003      2002
(millions, except EPS)                     

Net income contribution

     $ 190      $ 346      $ 268

EPS contribution

     $ 0.57      $ 1.09      $ 0.95

Gas transportation throughput (bcf)

       704        614        597

 

bcf = billion cubic feet

 

Presented below, on an after-tax basis, are the key factors impacting Dominion Energy’s operating results:

 

2004 vs. 2003

 

                Increase
(Decrease)
 
       Amount        EPS  
(millions, except EPS)                  

Energy trading and marketing

     $ (116 )      $ (0.37 )

Economic hedges

       (12 )        (0.04 )

Electric transmission revenue

       (15 )        (0.05 )

Other

       (13 )        (0.04 )

Share dilution

                (0.02 )

Change in net income contribution

     $ (156 )      $ (0.52 )

 

Dominion Energy’s net income contribution decreased $156 million, primarily reflecting:

  A loss from energy trading and marketing activities, reflecting comparatively lower price volatility on natural gas option positions and the effect of unfavorable price changes on electric trading margins;
  A decrease attributable to unfavorable price movements in 2004 on the economic hedges of Dominion Exploration & Production gas production described in Selected Information—Energy Trading Activities;
  Lower electric transmission revenue primarily due to decreased wheeling revenue resulting from lower contractual volumes and unfavorable market conditions; and
  Other factors including losses from asset and price risk management activities related to intersegment marketing.

 

2003 vs. 2002

 

              Increase
(Decrease)
 
       Amount      EPS  
(millions, except EPS)                

Energy trading and marketing

     $ 12      $ 0.05  

Economic hedges

       33        0.12  

Electric transmission margins

       11        0.04  

Cove Point operations

       9        0.03  

Revenue reallocation

       7        0.02  

Other

       6        0.02  

Share dilution

              (0.14 )

Change in net income contribution

     $ 78      $ 0.14  

 

Dominion Energy’s net income increased $78 million, primarily reflecting:

  An increase in the contribution of energy trading and marketing activities, reflecting an increase in margins on settled contracts, partially offset by a decrease in net mark-to-market gains on derivative contracts;
  An increase attributable to a reduction in net losses on the economic hedges of Dominion Exploration & Production gas production described in Selected Information—Energy Trading Activities;
  An increase in electric transmission margins due to customer growth and other factors, partially offset by the impact of unfavorable weather;
  A contribution from the Cove Point LNG facility due to its reactivation in August 2003; and
  A change in the allocation of electric base rate revenue among Dominion Generation, Dominion Energy and Dominion Delivery effective January 1, 2003;

 

Dominion Delivery

Dominion Delivery includes Dominion’s regulated electric and gas distribution and customer service business, as well as nonregulated retail energy marketing operations.

 

       2004      2003      2002
(millions, except EPS)                     

Net income contribution

     $ 466      $ 453      $ 422

EPS contribution

     $ 1.41      $ 1.42      $ 1.49

Electricity delivered (million mwhrs)

       78        75        75

Gas throughput (bcf)

       371        373        364

 

Presented below, on an after-tax basis, are the key factors impacting Dominion Delivery’s operating results:

 

2004 vs. 2003

 

               

Increase

(Decrease)

 
       Amount        EPS  
(millions, except EPS)                  

Weather

     $ (5 )      $ (0.02 )

Customer growth—utility operations

       9          0.03  

Nonregulated retail energy marketing operations

       32          0.10  

Reliability expenses

       (11 )        (0.03 )

Other

       (12 )        (0.04 )

Share dilution

                (0.05 )

Change in net income contribution

     $ 13        $ (0.01 )

 

Dominion Delivery’s net income contribution increased $13 million, primarily reflecting:

  A decrease in regulated gas sales due to comparably milder winter weather in regulated gas service territories; partially offset by an increase in regulated electric sales resulting from comparably favorable weather in regulated electric service territories;
  Customer growth in the electric and gas franchise service areas, primarily reflecting new residential electric customers;
 

A higher contribution from nonregulated retail energy marketing operations, primarily reflecting an increase in average customer accounts and higher electric and gas margins;

 

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  Higher reliability expenses, primarily due to increased tree trimming; and
  Other factors, including a decrease in net pension credits.

 

2003 vs. 2002

 

               

Increase

(Decrease)

 
       Amount        EPS  
(millions, except EPS)                  

Revenue reallocation

     $ 50        $ 0.18  

Customer growth—utility operations

       10          0.03  

Weather

       (5 )        (0.02 )

Income taxes

       (9 )        (0.03 )

Other

       (15 )        (0.05 )

Share dilution

                (0.18 )

Change in net income contribution

     $ 31        $ (0.07 )

 

Dominion Delivery’s net income contribution increased $31 million, primarily reflecting:

  A change in the allocation of electric base rate revenue among Dominion Generation, Dominion Energy and Dominion Delivery effective January 1, 2003;
  Customer growth in the electric and gas franchise service areas, primarily reflecting new residential electric customers;
  A decrease in regulated electric sales due to comparably milder weather in electric utility service territories, offset by an increase in regulated gas sales due to comparably colder weather in gas utility service territories;
  A decrease in net pension credits and an increase in other postretirement benefit costs; and
  The deferral of 2003 bad debt expenses as a regulatory asset, pending future recovery under a bad debt rider approved by the Public Utility Commission of Ohio, effective January 1, 2003.

 

Dominion Exploration & Production

Dominion Exploration & Production manages Dominion’s gas and oil exploration, development and production business.

 

     2004    2003    2002
(millions, except EPS)               

Net income contribution

   $ 595    $ 415    $ 380

EPS contribution

   $ 1.80    $ 1.30    $ 1.34

Gas production (bcf)

     359      384      385

Oil production (million bbls)

     10      9      10

Average realized prices with hedging results:(1)

                    

Gas (per mcf)(2)

   $ 4.09    $ 3.95    $ 3.40

Oil (per bbl)

     24.98      24.29      23.28

Average prices without hedging results:

                    

Gas (per mcf)(2)

     5.65      4.99      3.03

Oil (per bbl)

     39.07      29.82      24.44

DD&A (per mcfe)

   $ 1.30    $ 1.20    $ 1.12

Average production (lifting) cost (per mcfe)(3)

     0.92      0.80      0.60

 

bbl   = barrel
mcf   = thousand cubic feet
mcfe   = thousand cubic feet equivalent
(1)   Excludes the effects of the economic hedges discussed under Selected Information—Energy Trading Activities.
(2)   Excludes $223 million and $43 million of revenue recognized in 2004 and 2003, respectively, under the VPP agreements described in Note 12 to the Consolidated Financial Statements.
(3)   The exclusion of volumes produced and delivered under the VPP agreements accounted for approximately 75% of the increase from 2003 to 2004 and 8% of the increase from 2002 to 2003.

 

Presented below, on an after-tax basis, are the key factors impacting Dominion Exploration & Production’s operating results:

 

2004 vs. 2003

 

                Increase
(Decrease)
 
       Amount        EPS  
(millions, except EPS)                  

VPP revenue

     $ 114        $ 0.36  

Business interruption insurance

       61          0.19  

Gas and oil—production

       (55 )        (0.17 )

Gas and oil—prices

       49          0.15  

Operations and maintenance

       26          0.08  

DD&A—production

       13          0.04  

DD&A—rate

       (30 )        (0.09 )

Other

       2          0.01  

Share dilution

                (0.07 )

Change in net income contribution

     $ 180        $ 0.50  

 

Dominion Exploration & Production’s net income contribution increased $180 million, primarily reflecting:

  Recognition of revenue in connection with deliveries under the VPP agreements;
  The recognition of business interruption insurance revenue associated with the recovery of delayed gas and oil production due to Hurricane Ivan;
  Lower gas production reflecting the sale of mineral rights under the VPP agreements;
  Higher oil production reflecting production related to the deepwater Gulf of Mexico Devils Tower project;
  Higher average realized prices for gas and oil;
  Lower operations and maintenance expenses, primarily due to favorable changes in the fair value of certain oil options, partially offset by an increase in production costs; and
  A higher rate for depreciation, depletion and amortization, primarily reflecting higher industry finding and development costs, increased acquisition costs and the effect of the reduction in reserves attributable to the VPP transactions.

 

2003 vs. 2002

 

                Increase
(Decrease)
 
       Amount        EPS  
(millions, except EPS)                  

Gas and oil—prices

     $ 133        $ 0.47  

Gas and oil—production

       (18 )        (0.06 )

VPP revenue

       27          0.10  

DD&A—rate

       (22 )        (0.08 )

DD&A—production

       3          0.01  

Operations and maintenance

       (41 )        (0.15 )

Severance taxes

       (18 )        (0.06 )

Income taxes

       (20 )        (0.07 )

Other

       (9 )        (0.03 )

Share dilution

                (0.17 )

Change in net income contribution

     $ 35        $ (0.04 )

 

Dominion Exploration & Production’s net income contribution increased $35 million, primarily reflecting:

  Higher average realized prices for gas and oil;
 

Lower oil production, reflecting declines in Gulf of Mexico shelf and deepwater production. Lower gas production, reflecting the

 

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  sale of mineral rights under a VPP agreement and declines in Rocky Mountain and Michigan production, was largely offset by increased Gulf of Mexico gas production;
  A higher rate for depreciation, depletion and amortization in 2003, primarily reflecting increased acquisition, finding and development costs;
  Higher operations and maintenance expenses which increased in connection with overall higher commodity prices in 2003, that caused an increase in the demand for equipment, labor and services;
  Higher severance taxes, resulting from higher gas and oil revenue associated with higher commodity prices; and
  Higher income taxes, primarily reflecting the expiration of Section 29 production tax credits beginning in 2003, partially offset by a reduction in tax rates applied to deferred taxes associated with Canadian operations.

 

Corporate and Other

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

 

       2004        2003        2002  
(millions, except EPS amounts)                           

Specific items attributable to operating segments

     $ (224 )      $ (220 )      $ 7  

DCI operations

       (82 )        (96 )        14  

Telecommunications operations(1)

       (13 )        (750 )        (26 )

Other corporate operations

       (208 )        (342 )        (264 )

Total net expense

       (527 )        (1,408 )        (269 )

Earnings per share impact

     $ (1.59 )      $ (4.41 )      $ (0.94 )

 

(1)   $15 million and $642 million are classified as discontinued operations in 2004 and 2003, respectively.

 

Specific Items Attributable to Operating Segments—2004

During 2004, Dominion reported net expenses of $224 million in the Corporate and Other segment attributable to its operating segments. The net expenses in 2004 primarily related to the impact of the following:

  A $184 million charge ($112 million after-tax) related to the valuation of Dominion’s interest in a long-term power tolling contract, attributable to Dominion Generation;
  $96 million of losses ($61 million after-tax) related to the discontinuance of hedge accounting for certain oil hedges, resulting from an interruption of oil production in the Gulf of Mexico caused by Hurricane Ivan, and subsequent changes in the fair value of those hedges during the third quarter, attributable to Dominion Exploration & Production; and
  $71 million of charges ($43 million after-tax) resulting from the termination of certain long-term power purchase contracts, attributable to Dominion Generation.

 

Specific Items Attributable to Operating Segments—2003

During 2003, Dominion reported net expenses of $220 million in the Corporate and Other segment attributable to its operating segments. The net expenses in 2003 primarily related to the impact of the following:

  $21 million net after-tax gain representing the cumulative effect of adopting new accounting principles, as described in Note 3 to the Consolidated Financial Statements, including:
    SFAS No. 143: a $180 million after-tax gain attributable to: Dominion Generation ($188 million after-tax gain); Dominion Exploration & Production ($7 million after-tax loss); and Dominion Delivery ($1 million after-tax loss);
    EITF 02-3: a $67 million after-tax loss attributable to Dominion Energy;
    Statement 133 Implementation Issue No. C20: a $75 million after-tax loss attributable to Dominion Generation; and
    FIN 46R: a $17 million after-tax loss attributable to Dominion Generation;
  $197 million of operations and maintenance expense ($122 million after-tax), representing incremental restoration expenses associated with Hurricane Isabel, attributable primarily to Dominion Delivery;
  A $105 million charge ($65 million after-tax) for the termination of power purchase contracts attributable to Dominion Generation;
  A $64 million charge ($39 million after-tax) for the restructuring and termination of certain electric sales contracts attributable to Dominion Generation; and
  $26 million of severance costs ($15 million after-tax) for workforce reductions during the first quarter of 2003, attributable to:
    Dominion Generation ($8 million after-tax);
    Dominion Energy ($2 million after-tax);
    Dominion Delivery ($4 million after-tax); and
    Dominion Exploration & Production ($1 million after-tax).

 

DCI Operations

DCI recognized a net loss of $82 million in 2004; a decrease of $14 million as compared to 2003. The decrease primarily resulted from a $20 million reduction in after-tax charges associated with asset impairments.

DCI recognized a net loss of $96 million in 2003, compared to net income of $14 million in 2002. The loss resulted primarily from the recognition of the following charges recognized in 2003: $108 million ($70 million after-tax) of impairments related to retained interests from securitizations, goodwill and other investments, and the sale of financial assets; and a $26 million valuation allowance established on certain deferred tax assets.

 

Telecommunications Operations

Dominion’s loss from its discontinued telecommunications business decreased $737 million to $13 million in 2004, primarily as a result of its sale in May 2004 and the impact of certain charges recognized during 2003 which are discussed below.

Dominion’s loss from its telecommunications business increased $724 million to $750 million in 2003, primarily reflecting:

  $566 million associated with the impairment of network assets and related inventories. Dominion did not recognize any deferred tax benefits related to the impairment charges, since realization of tax benefits is not anticipated at this time based on Dominion’s expected future tax profile;
  A $48 million increase in deferred tax expense as a result of the increase in the valuation allowance on deferred tax assets;

 

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Dominion’s purchase of the remaining equity interest in DFV held by another party for $62 million in December 2003, $60 million of which was recorded as goodwill and impaired;

  $57 million ($35 million after-tax) for the costs associated with Dominion’s acquisition of DFV senior notes; and
  $41 million of after-tax operating losses.

 

Other Corporate Operations

The net expenses associated with other corporate operations for 2004 decreased by $134 million as compared to 2003, predominantly due to a $28 million after-tax benefit associated with the disposition of CNGI’s investment in Australian pipeline assets that were sold during 2004, lower interest expense and the impact in 2003 of the charges discussed below.

The net expenses associated with other corporate operations for 2003 increased by $78 million as compared to 2002, primarily reflecting:

  A $22 million ($14 million after-tax) impairment related to CNGI’s generation assets that were sold in December 2003;
  A $62 million ($55 million after-tax) impairment of CNGI’s investment in Australian pipeline assets held for sale; and
  A $16 million ($10 million after-tax) loss representing the cumulative effect of adopting FIN 46R.

 

Selected Information—Energy Trading Activities

As previously described, Dominion manages its energy trading, hedging and marketing activities through the Clearinghouse. Dominion believes these operations complement its integrated energy businesses and facilitate its risk management activities. As part of these operations, the Clearinghouse enters into contracts for purchases and sales of energy-related commodities, including coal, natural gas, electricity, oil and emissions credits. Settlements of contracts may require physical delivery of the underlying commodity or cash settlement. The Clearinghouse enters into contracts with the objective of benefiting from changes in prices. For example, after entering into a contract to purchase a commodity, the Clearinghouse typically enters into a sales contract, or a combination of sales contracts, with quantities and delivery or settlement terms that are identical or very similar to those of the purchase contract. When the purchase and sales contracts are settled either by physical delivery of the underlying commodity or by net cash settlement, the Clearinghouse may receive a net cash margin (a realized gain), or may pay a net cash margin (a realized loss). Clearinghouse management continually monitors its contract positions, considering location and timing of delivery or settlement for each energy commodity in relation to market price activity.

In addition, the Clearinghouse held a portfolio of financial derivative instruments to manage Dominion’s price risk associated with a portion of its anticipated sales of 2004 natural gas production that had not been considered in the hedging activities of the Dominion Exploration & Production segment (economic hedges). In 2004, Dominion Energy recognized a net loss of $22 million on the economic hedges. As anticipated, Dominion Exploration & Production sold sufficient volumes of natural gas in 2004 at market prices, which, when combined with the settlement of the economic hedges, resulted in a range of prices for those sales contemplated by the risk management strategy.

During the fourth quarter of 2004, Dominion performed an evaluation of its Clearinghouse trading and marketing operations, which resulted in a decision to exit certain energy trading activities and instead focus on the optimization of company assets. Beginning in 2005, all revenues and expenses from the Clearinghouse’s optimization of company assets will be reported as part of the results of the business segments operating the related assets.

A summary of the changes in the unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes, including the economic hedges, during 2004 follows:

 

       Amount
(millions)       

Net unrealized gain at December 31, 2003

     $ 33

Contracts realized or otherwise settled during the period

       15

Net unrealized gain at inception of contracts initiated during the period

      

Changes in valuation techniques

      

Other changes in fair value

       98

Net unrealized gain at December 31, 2004

     $ 146

 

The balance of net unrealized gains and losses recognized for Dominion’s energy-related derivative instruments held for trading purposes, including the economic hedges at December 31, 2004, is summarized in the following table based on the approach used to determine fair value and contract settlement or delivery dates:

 

    

Maturity Based on Contract Settlement

or Delivery Date(s)

Source of Fair Value    Less
than 1
year
   1-2 years    2-3
years
   3-5
years
   In Excess
of 5
years
   Total
(millions)                              

Actively quoted(1)

   $ 105    $ 15    $ 5            $ 125

Other external sources(2)

          14      5    $ 2         21

Models and other valuation methods

                           

Total

   $ 105    $ 29    $ 10    $ 2       $ 146

 

(1)   Exchange-traded and over-the-counter contracts.
(2)   Values based on prices from over-the-counter broker activity and industry services and, where applicable, conventional option pricing models.

 

Sources and Uses of Cash

Dominion and its subsidiaries depend on both internal and external sources of liquidity to provide working capital and to fund capital requirements. Short-term cash requirements not met by cash provided by operations are generally satisfied with proceeds from short-term borrowings. Long-term cash needs are met through sales of securities and additional long-term financing.

At December 31, 2004, Dominion had cash and cash equivalents of $389 million with $2.4 billion of unused capacity under its credit facilities. For long-term financing needs, amounts available for debt or equity offerings under currently effective shelf registrations totaled $2.5 billion at February 1, 2005.

 

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Operating Cash Flows

As presented on Dominion’s Consolidated Statements of Cash Flows, net cash flows from operating activities were $2.8 billion, $2.4 billion and $2.4 billion for the years ended December 31, 2004, 2003 and 2002, respectively. Dominion’s management believes that its operations provide a stable source of cash flow sufficient to contribute to planned levels of capital expenditures and maintain or grow the dividend on common shares.

Dominion’s operations are subject to risks and uncertainties that may negatively impact the timing or amounts of operating cash flow, including:

  Cost-recovery shortfalls due to capped base and fuel rates in effect in Virginia for its regulated electric utility;
  The collection of business interruption insurance proceeds associated with the recovery of delayed gas and oil production due to Hurricane Ivan;
  Unusual weather and its effect on energy sales to customers and energy commodity prices;
  Extreme weather events that could disrupt gas and oil production or cause catastrophic damage to Dominion’s electric distribution and transmission systems;
  Exposure to unanticipated changes in prices for energy commodities purchased or sold, including the effect on derivative instruments that may require the use of funds to post margin deposits with counterparties;
  Effectiveness of Dominion’s risk management activities and underlying assessment of market conditions and related factors, including energy commodity prices, basis, liquidity, volatility, counterparty credit risk, availability of generation and transmission capacity, currency exchange rates and interest rates;
  The cost of replacement electric energy in the event of longer-than-expected or unscheduled generation outages;
  Contractual or regulatory restrictions on transfers of funds among Dominion and its subsidiaries; and
  Timeliness of recovery for costs subject to cost-of-service utility rate regulation.

 

Credit Risk

Dominion’s exposure to potential concentrations of credit risk results primarily from its energy trading, marketing and hedging activities and sales of gas and oil production. Presented below is a summary of Dominion’s gross and net credit exposure as of December 31, 2004 for these activities. Dominion calculates its gross credit exposure for each counterparty as the unrealized fair value of derivative contracts plus any outstanding receivables (net of payables, where netting agreements exist), prior to the application of collateral.

 

     Gross
Credit
Exposure
   Credit
Collateral
   Net
Credit
Exposure
(millions)               

Investment grade(1)

   $ 784    $ 23    $ 761

Non-investment grade(2)

     36           36

No external ratings:

                    

Internally rated—investment grade(3)

     299           299

Internally rated—non-investment grade(4)

     150           150

Total

   $ 1,269    $ 23    $ 1,246

 

(1)   Designations as investment grade are based upon minimum credit ratings assigned by Moody’s Investors Service (Moody’s) and Standard & Poor’s Rating Group, a division of the McGraw-Hill Companies, Inc. (Standard & Poor’s) . The five largest counterparty exposures, combined, for this category represented approximately 16% of the total gross credit exposure.
(2)   The five largest counterparty exposures, combined, for this category represented approximately 2% of the total gross credit exposure.
(3)   The five largest counterparty exposures, combined, for this category represented approximately 14% of the total gross credit exposure.
(4)   The five largest counterparty exposures, combined, for this category represented approximately 3% of the total gross credit exposure.

 

Investing Cash Flows

During 2004, 2003 and 2002, investing activities resulted in net cash outflows of $1.3 billion, $3.4 billion, and $4.0 billion respectively. Significant investing activities for 2004 included:

  $1.5 billion of capital expenditures for the construction and expansion of generation facilities, environmental upgrades, purchase of nuclear fuel, and construction and improvements of gas and electric transmission and distribution assets;
  $1.3 billion of capital expenditures for the purchase and development of gas and oil producing properties, drilling and equipment costs and undeveloped lease acquisitions;
  $729 million of proceeds from sales of gas and oil mineral rights and properties;
  $490 million for the purchase of securities and $466 million for the sale of securities, primarily related to investments held in nuclear decommissioning trusts; and
  $132 million in advances and $806 million in reimbursements related to the Fairless generation project in Pennsylvania.

 

Financing Cash Flows and Liquidity

Dominion, Virginia Electric and Power Company (Virginia Power) and Consolidated Natural Gas Company (CNG) (collectively the Dominion Companies) rely on bank and capital markets as a significant source of funding for capital requirements not satisfied by cash provided by the companies’ operations. As discussed further in the Credit Ratings section below, the Dominion Companies’ ability to borrow funds or issue securities and the return demanded by investors are affected by the issuing company’s credit ratings. In addition, the raising of external capital is subject to certain regulatory approvals, including authorization by the SEC and, in the case of Virginia Power, the Virginia State Corporation Commission (Virginia Commission).

During 2004, net cash used in financing activities was $1.3 billion. During 2003 and 2002, net cash flows from financing activities were $853 million and $1.3 billion, respectively. During 2004, the Dominion Companies issued long-term debt (net of exchanged debt) and common stock totaling approximately $1.7 billion. The proceeds were used primarily to repay debt.

 

Credit Facilities and Short-Term Debt

The Dominion Companies use short-term debt, primarily commercial paper, to fund working capital requirements, as a bridge to long-term debt financing and as bridge financing for acquisitions, if applicable. The levels of borrowing may vary significantly during the course of the year, depending upon the timing and amount of cash requirements not satisfied by cash from operations. At December 31, 2004, the Dominion Companies had committed lines of credit totaling $3.75 billion. Although there were no loans outstanding, these lines of credit support commercial paper borrowings and letter of credit issuances. At December 31,

 

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2004, the Dominion Companies had the following commercial paper and letters of credit outstanding and capacity available under credit facilities:

 

     Facility
Limit
   Outstanding
Commercial
Paper
   Outstanding
Letters of
Credit
   Facility
Capacity
Available
(millions)                    

Three-year revolving credit facility(1)

   $ 1,500                     

Three-year revolving credit facility(2)

     750                     

Total joint credit facilities

     2,250    $ 573    $ 183    $ 1,494

Three-year CNG credit facility(3)

     1,500           555      945

Totals

   $ 3,750    $ 573    $ 738    $ 2,439

 

(1)   The $1.5 billion three-year revolving credit facility was entered into in May 2004 and terminates in May 2007. This credit facility can also be used to support up to $500 million of letters of credit.
(2)   The $750 million three-year revolving credit facility was entered into in May 2002 and can also be used to support up to $200 million of letters of credit. Dominion expects to renew this facility prior to its maturity in May 2005.
(3)   The $1.5 billion three-year credit facility is used to support the issuance of letters of credit and commercial paper by CNG to fund collateral requirements under its gas and oil hedging program. The facility was entered into in August 2004 and terminates in August 2007.

 

In addition to the facilities above, in June and August of 2004, CNG entered into two $100 million letter of credit agreements that terminate in June 2007 and August 2009, respectively. Additionally, in October 2004, CNG entered into three letter of credit agreements totaling $700 million that terminate in April 2005 and are not expected to be renewed. These five agreements support letter of credit issuances, providing collateral required on derivative financial contracts used by CNG in its risk management strategies for gas and oil production. At December 31, 2004, outstanding letters of credit under these agreements totaled $900 million.

Dominion’s financial policy precludes issuing commercial paper in excess of its supporting lines of credit. At December 31, 2004, the total amount of commercial paper outstanding was $573 million and the total amount of letter of credit issuances was $738 million, leaving approximately $2.4 billion available for issuance. The Dominion Companies are required to pay minimal annual commitment fees to maintain the credit facilities.

In addition, these credit agreements contain various terms and conditions that could affect the Dominion Companies’ ability to borrow under these facilities. They include maximum debt to total capital ratios, material adverse change clauses and cross-default provisions.

All of the credit facilities include a defined maximum total debt to total capital ratio. As of December 31, 2004, the calculated ratio for the Dominion Companies, pursuant to the terms of the agreements, was as follows:

 

Company      Maximum
Ratio
     Actual
Ratio(1)

Dominion Resources, Inc.

     65%      55%

Virginia Power

     60%      50%

CNG

     60%      51%

 

(1)   Indebtedness as defined by the bank agreements excludes certain junior subordinated notes payable to affiliated trusts and mandatorily convertible securities that are reflected on the Consolidated Balance Sheets.

 

These provisions apply separately to Dominion Resources, Inc., Virginia Power and CNG. If any one of the Dominion Companies or any of that specific company’s material subsidiaries fail to make payment on various debt obligations in excess of $25 million, the lenders could require that respective company to accelerate its repayment of any outstanding borrowings under the credit facility and the lenders could terminate their commitment to lend funds to that company. Accordingly, any defaults on indebtedness by CNG or any of its material subsidiaries would not affect the lenders’ commitment to Virginia Power. Similarly, any defaults on indebtedness by Virginia Power or any of its material subsidiaries would not affect the lenders’ commitment to CNG. However, any default by either CNG or Virginia Power would also affect in like manner the lenders’ commitment to Dominion Resources, Inc. under the joint credit agreements.

Although the joint credit agreements contain material adverse change clauses, the participating lenders, under those specific provisions, cannot refuse to advance funds to any of the Dominion Companies for the repurchase of its outstanding commercial paper.

 

Long-Term Debt

During 2004, Dominion Resources, Inc. and its subsidiaries issued the following long-term debt:

 

Type   Principal   Rate   Maturity    Issuing Company
    (millions)             

Senior notes

  $ 200   5.20%   2016    Dominion Resources, Inc.

Senior notes

    100   Variable   2006    Dominion Resources, Inc.

Senior notes

    400   5.00%   2014    CNG

Senior notes

    177   4.92%   2009    Dominion Canada Finance
Corporation

Total long-term debt issued

  $ 877             

 

During 2004, Dominion Resources, Inc. and its subsidiaries repaid $1.3 billion of long-term debt securities.

In 2004, Dominion exchanged $219 million of outstanding contingent convertible senior notes for new notes with a conversion feature that requires that the principal amount of each note be repaid in cash upon conversion.

In 2004, in connection with the acquisition of certain generating facilities, Virginia Power assumed $109 million of private placement bonds and $104 million of pollution control bonds. Virginia Power exchanged $106 million of its 2004 Series A 7.25% senior notes due 2017 for $106 million of the private placement bonds. The senior notes have the same financial terms as the private placement bonds, but are registered securities.

 

Common Stock

During 2004, Dominion issued 14 million shares of common stock and received proceeds of $839 million. Of this amount, 7 million shares and proceeds of $413 million resulted from the settlement of stock purchase contracts associated with Dominion’s 2000 issuance of equity-linked debt securities. The remainder of the shares issued and proceeds received were through Dominion Direct® (a dividend reinvestment and open enrollment direct stock purchase plan), employee savings plans and the exercise of employee stock options. In 2005, Dominion Direct® and the Dominion employee savings plans will purchase Dominion common stock on the open market with the proceeds received through these programs, rather than having additional new common shares issued.

 

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In July 1998, Dominion was authorized by its Board of Directors to repurchase up to the lesser of 16.5 million shares, or $650 million of its outstanding common stock. As of December 31, 2004, Dominion had repurchased approximately 12 million shares for $537 million, with its last repurchase occurring in 2002. In February 2005, in order to recognize the significant increase in the size of the company and the market value of its common stock since the time of the previous authorization, Dominion’s Board of Directors superseded this authority, with new authority, to repurchase up to the lesser of 25 million shares or $2.0 billion of Dominion’s outstanding common stock.

 

Forward Equity Transaction

In September 2004, Dominion entered into a forward equity sale agreement (forward agreement) with Merrill Lynch International (MLI), as forward purchaser, relating to 10 million shares of Dominion’s common stock. The forward agreement provides for the sale of two tranches of Dominion common stock, each with stated maturity dates and settlement prices. In connection with the forward agreement, MLI borrowed an equal number of shares of Dominion’s common stock from stock lenders and, at Dominion’s request, sold the borrowed shares to J.P. Morgan Securities Inc. (JPM) under a purchase agreement among Dominion, MLI and JPM. JPM subsequently offered the borrowed shares to the public. Dominion accounted for the forward agreement as equity at its initial fair value but did not receive any proceeds from the sale of the borrowed shares.

The use of a forward agreement allows Dominion to avoid equity market uncertainty by pricing a stock offering under then existing market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed. Except in specified circumstances or events that would require physical share settlement, Dominion may elect to settle the forward agreement by means of a physical share, cash or net share settlement and may also elect to settle the agreement in whole, or in part, earlier than the stated maturity date at fixed settlement prices. Under either a physical share or net share settlement, the maximum number of shares deliverable by Dominion under the terms of the forward agreement was limited to the 10 million shares specified in the two tranches. Assuming gross share settlement of all shares under the forward agreement, Dominion would have received aggregate proceeds of approximately $644 million, based on maturity forward prices of $64.62 per share for the 2 million shares included in the first tranche and $64.34 per share for the 8 million shares included in the second tranche.

However, Dominion elected to cash settle the first tranche in December 2004 and made a payment to MLI for $5.8 million, representing the difference between Dominion’s share price and the applicable forward sale price, multiplied by the 2 million shares. Dominion recorded the settlement payment as a reduction to common stock in its Consolidated Balance Sheet. Additionally, Dominion elected to cash settle 3 million shares of the second tranche in February 2005 and made a payment to MLI for $17.4 million.

The remaining 5 million shares of the second tranche must be settled by May 17, 2005. If gross share settlement were elected for the remainder of the second tranche at its maturity date, Dominion would receive aggregate proceeds of approximately $322 million and would deliver 5 million of its common shares. In the event any or all of the proceeds are not needed, Dominion has the option to either cash settle or net share settle the remainder of the second tranche of the forward agreement in whole, or in part, and may elect settlement earlier than the stated maturity date. If Dominion elects to cash or net share settle any portion of the remainder of the second tranche, the payment is based on the difference between Dominion’s share price and the applicable forward sale price for the second tranche, multiplied by the number of shares being settled.

If, at December 31, 2004, Dominion had elected a cash settlement of the 8 million shares in the second tranche, Dominion would have owed MLI $28 million, of which, $18 million would have represented settlement of the 5 million shares remaining in the second tranche after the February 2005 settlement. If, at the time of cash settlement, Dominion’s current share price were lower than the forward sale price, Dominion would receive a payment from MLI. For every dollar increase (decrease) in the value of Dominion’s stock, the value of the settlement of the shares remaining in the second tranche from MLI’s perspective would increase (decrease) by $5 million.

Dominion expects to use proceeds received from physical share settlements under the remainder of the second tranche of the forward agreement to fund part of the cost of acquiring the Kewaunee nuclear power plant in Wisconsin for $220 million (which is expected to close in the first half of 2005) and the acquisition of three electric generating stations from USGen for $642 million (which closed on January 1, 2005).

 

Amounts Available under Shelf Registrations

At February 1, 2005, Dominion Resources, Inc., Virginia Power, and CNG had approximately $941 million, $670 million, and $900 million, respectively, of available capacity under currently effective shelf registrations. Securities that may be issued under these shelf registrations, depending upon the registrant, include senior notes (including medium-term notes), subordinated notes, first and refunding mortgage bonds, trust preferred securities, preferred stock and common stock.

In addition, Dominion Resources, Inc., under a separate shelf registration has 6.9 million shares of common stock available exclusively for delivery against stock purchase contracts associated with outstanding equity-linked debt securites.

In December 2004, the SEC granted Dominion’s request for financing authorization under the 1935 Act through December 31, 2007. This authority replaced the previous financing authority granted by the SEC, which expired December 31, 2004.

 

Credit Ratings

Credit ratings are intended to provide banks and capital market participants with a framework for comparing the credit quality of securities and are not a recommendation to buy, sell or hold securities. Management believes that the current credit ratings of the Dominion Companies provide sufficient access to the capital markets. However, disruptions in the banking and capital markets not specifically related to Dominion may affect the Dominion Companies’ ability to access these funding sources or cause an increase in the return required by investors.

Both quantitative (financial strength) and qualitative (business or operating characteristics) factors are considered by the credit rating agencies in establishing an individual company’s credit rating. Credit ratings should be evaluated independently and are

 

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subject to revision or withdrawal at any time by the assigning rating organization. The credit ratings for the Dominion Companies are most affected by each company’s financial profile, mix of regulated and nonregulated businesses and respective cash flows, changes in methodologies used by the rating agencies and “event risk,” if applicable, such as major acquisitions.

Credit ratings for the Dominion Companies as of February 1, 2005 follow:

 

       Standard
& Poor’s
     Moody’s

Dominion Resources, Inc.

             

Senior unsecured debt securities

     BBB+      Baa1

Preferred securities of affiliated trusts

     BBB-      Baa2

Commercial paper

     A-2      P-2

Virginia Power

             

Mortgage bonds

     A-      A2

Senior unsecured (including tax-exempt) debt securities

     BBB+      A3

Preferred securities of affiliated trust

     BBB-      Baa1

Preferred stock

     BBB-      Baa2

Commercial paper

     A-2      P-1

CNG

             

Senior unsecured debt securities

     BBB+      A3

Preferred securities of affiliated trust

     BBB-      Baa1

Commercial paper

     A-2      P-2

 

As of February 1, 2005, Moody’s maintains a negative outlook for its ratings of CNG and Standard & Poor’s maintains a negative outlook for its ratings of Dominion Resources, Inc., Virginia Power and CNG.

Generally, a downgrade in an individual company’s credit rating would not restrict its ability to raise short-term and long-term financing so long as its credit rating remains “investment grade,” but it would increase the cost of borrowing. Dominion works closely with both Standard & Poor’s and Moody’s with the objective of maintaining its current credit ratings. As discussed in Risk Factors and Cautionary Statements That May Affect Future Results, in order to maintain its current ratings, Dominion may find it necessary to modify its business plans and such changes may adversely affect its growth and earnings per share.

 

Debt Covenants

As part of borrowing funds and issuing debt (both short-term and long-term) or preferred securities, the Dominion Companies must enter into enabling agreements. These agreements contain covenants that, in the event of default, could result in the acceleration of principal and interest payments; restrictions on distributions related to its capital stock, including dividends, redemptions, repurchases, liquidation payments or guarantee payments; and in some cases, the termination of credit commitments unless a waiver of such requirements is agreed to by the lenders/security holders. These provisions are customary, with each agreement specifying which covenants apply. These provisions are not necessarily unique to the Dominion Companies. Some of the typical covenants include:

  The timely payment of principal and interest;
 

Information requirements, including submitting financial reports filed with the SEC to lenders;

  Performance obligations, audits/inspections, continuation of the basic nature of business, restrictions on certain matters related to merger or consolidation, restrictions on disposition of substantial assets;
  Compliance with collateral minimums or requirements related to mortgage bonds; and
  Limitations on liens.

Dominion monitors the covenants on a regular basis in order to ensure that events of default will not occur. As of December 31, 2004, there were no events of default under the Dominion Companies’ covenants.

 

 

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Future Cash Payments for Contractual Obligations and Planned Capital Expenditures

Dominion is party to numerous contracts and arrangements obligating Dominion to make cash payments in future years. These contracts include financing arrangements such as debt agreements and leases, as well as contracts for the purchase of goods and services and financial derivatives. Presented below is a table summarizing cash payments that may result from contracts to which Dominion is a party as of December 31, 2004. For purchase obligations and other liabilities, amounts are based upon contract terms, including fixed and minimum quantities to be purchased at fixed or market-based prices. Actual cash payments will be based upon actual quantities purchased and prices paid and will likely differ from amounts presented below. The table excludes all amounts classified as current liabilities on the Consolidated Balance Sheets, other than current maturities of long-term debt and interest payable. The majority of current liabilities will be paid in cash in 2005.

 

    Less
than
1 Year
 

1-3

years

 

3-5

years

 

More

than 5

years

  Total
(millions)                    

Long-term debt(1)

  $ 1,368   $ 3,948   $ 1,807   $ 9,810   $ 16,933

Interest payments(2)

    974     1,682     1,346     7,339     11,341

Leases

    133     225     184     365     907

Purchase obligations(3):

                             

Purchased electric capacity for utility operations

    509     968     858     3,103     5,438

Fuel used for utility operations

    691     673     245     51     1,660

Fuel used for nonregulated operations

    48     76     70         194

Production handling

    56     105     61     27     249

Pipeline transportation and storage

    82     118     85     95     380

Energy commodity purchases for resale(4)

    527     131     3         661

Other

    352     254     35     5     646

Other long-term liabilities(5):

                             

Financial derivatives-

commodities(4)

    1,084     858     1         1,943

Other contractual obligations

    25     32     14     32     103

Total cash payments

  $ 5,849   $ 9,070   $ 4,709   $ 20,827   $ 40,455

 

(1)   Based on stated maturity dates rather than the earlier redemption dates that could be elected by instrument holders.
(2)   Does not reflect Dominion's ability to defer distributions related to its junior subordinated notes payable to affiliated trusts.
(3)   Amounts exclude open purchase orders for services that are provided on demand, the timing of which cannot be determined.
(4)   Represents the summation of settlement amounts, by contracts, due from Dominion if all physical or financial transactions among Dominion and its counterparties were liquidated and terminated.
(5)   Excludes regulatory liabilities, AROs and employee benefit plan obligations that are not contractually fixed as to timing and amount. See Notes 14, 15 and 21 to the Consolidated Financial Statements. Deferred income taxes are also excluded since cash payments are based primarily on taxable income for each discrete fiscal year.

 

Dominion’s planned capital expenditures during 2005 are expected to total approximately $3.6 billion, which includes the cost of acquiring USGen and certain non-utility generating facilities. For 2006, planned capital expenditures are expected to be approximately $3.0 billion. These expenditures include construction and expansion of generation facilities, environmental upgrades, construction improvements and expansion of gas and electric transmission and distribution assets, purchases of nuclear fuel and expenditures to explore for and develop natural gas and oil properties. Dominion expects to fund its capital expenditures with cash from operations and a combination of sales of securities and short-term borrowings.

Dominion may choose to postpone or cancel certain planned capital expenditures in order to mitigate the need for future debt financings.

 

Use of Off-Balance Sheet Arrangements

Leasing Arrangements

Dominion has an agreement with a voting interest entity (lessor) to lease the Fairless power station in Pennsylvania, which began commercial operations in June 2004. During construction, Dominion acted as the construction agent for the lessor, controlled the design and construction of the facility and has since been reimbursed for all project costs advanced to the lessor. Project costs totaled $898 million at December 31, 2004. Dominion will make annual lease payments of $53 million. The lease expires in 2013 and at that time, Dominion may renew the lease at negotiated amounts based on original project costs and current market conditions, subject to lessor approval; purchase Fairless at its original construction cost; or sell Fairless, on behalf of the lessor, to an independent third party. If Fairless is sold and the proceeds from the sale are less than its original construction cost, Dominion would be required to make a payment to the lessor in an amount up to 70.75% of original project costs adjusted for certain other costs as specified in the lease. The lease agreement does not contain any provisions that involve credit rating or stock price trigger events.

Benefits of this arrangement include:

  Certain tax benefits as Dominion is considered the owner of the leased property for tax purposes. As a result, it is entitled to tax deductions for depreciation not recognized for financial accounting purposes; and
  As an operating lease for financial accounting purposes, the asset and related borrowings used to finance the construction of the asset are not included on Dominion’s Consolidated Balance Sheets. Although this improves measures of leverage calculated using amounts reported in Dominion’s Consolidated Financial Statements, credit rating agencies view lease obligations as debt equivalents in evaluating Dominion’s credit profile.

 

Securitizations of Mortgages and Loans

As of December 31, 2004, Dominion held $335 million of retained interests from securitizations of mortgage and commercial loans completed in prior years. Dominion did not securitize or originate any loans in 2004. Investors in the securitization trusts have no recourse to Dominion’s other assets for failure of debtors to repay principal and interest on the underlying loans when due. Therefore, Dominion’s exposure to any future losses from this activity is limited to its investment in retained interests.

 

 

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Forward Equity Transaction

As described in Financing Cash Flows and Liquidity—Forward Equity Transaction, in September 2004, Dominion entered into a forward equity sale agreement relating to 10 million shares of Dominion’s common stock. The use of a forward agreement allows Dominion to avoid equity market uncertainty by pricing a stock offering under then current market conditions, while mitigating share dilution by postponing the issuance of stock until funds are needed. If Dominion decides it does not need any or all of the proceeds, it has the option to cash settle or net share settle the forward sale agreement in whole, or in part.

 

Future Issues and Other Matters

Status of Electric Deregulation in Virginia

The Virginia Electric Utility Restructuring Act (Virginia Restructuring Act) was enacted in 1999 and established a plan to restructure the electric utility industry in Virginia. The Virginia Restructuring Act addressed among other things: capped base rates, regional transmission organization (RTO) participation, retail choice, the recovery of stranded costs and the functional separation of a utility’s electric generation from its electric transmission and distribution operations.

Retail choice has been available to all of Dominion’s Virginia regulated electric customers since January 1, 2003. Dominion has also separated its generation, distribution and transmission functions through the creation of divisions. Virginia codes of conduct ensure that Dominion’s generation and other divisions operate independently and prevent cross-subsidies between the generation and other divisions.

Since the passage of the Virginia Restructuring Act, the competitive environment has not developed in Virginia as anticipated. In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates by three and one-half years, to December 31, 2010, unless modified or terminated earlier under the Virginia Restructuring Act. In addition to extending capped rates, the amendments:

  Lock in Dominion’s fuel factor provisions until the earlier of July 1, 2007 or the termination of capped rates;
  Provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010 (unless capped rates are terminated earlier under the Virginia Restructuring Act), with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting for the Virginia jurisdiction; and
  End wires charges on the earlier of July 1, 2007 or the termination of capped rates, consistent with the Virginia Restructuring Act’s original timetable.

The risk of fuel factor-related cost recovery shortfalls may adversely impact Dominion’s cost structure during the transition period, and Dominion could realize the negative economic impact of any such adverse event. Conversely, Dominion may experience a positive economic impact to the extent that it can reduce its fuel factor-related costs for its electric utility generation-related operations.

Dominion anticipates that its unhedged natural gas and oil production will act as a natural internal hedge for electric generation. If gas and oil prices rise, it is expected that Dominion’s exploration and production operations will earn greater profits that will help offset higher fuel costs and lower profits in Dominion’s electric generation operations. Conversely, if gas and oil prices fall, it is expected that Dominion’s electric generation operations will incur lower fuel costs and earn higher profits that will offset lower profits in Dominion’s exploration and production operations. Dominion also anticipates that the fixed fuel rate will lessen the impact of seasonally mild weather on its electric generation operations. During periods of mild weather it is expected that electric generation operations will burn less high-cost fuel because customers will use less electricity, thereby offsetting decreased revenues. Alternatively, in periods of extreme weather, Dominion’s higher fuel costs from running costlier plants are expected to be mitigated by additional revenue as customers use more electricity.

Other amendments to the Virginia Restructuring Act were also enacted with respect to a minimum stay exemption program, a wires charges exemption program and allowing the development of a coal-fired generating plant in southwest Virginia for serving default service needs. Under the minimum stay exemption program, large customers with a load of 500 kW or greater would be exempt from the twelve-month minimum stay obligation under capped rates if they return to supply service from the incumbent utility at market-based pricing after they have switched to supply service with a competitive service provider. The wires charge exemption program would allow large industrial and commercial customers, as well as aggregated customers in all rate classes, to avoid paying wires charges by agreeing to market-based pricing upon return to the incumbent electric utility. In January 2005, Dominion filed compliance plans for both of these programs.

 

RTO

In September 2002, Dominion and PJM Interconnection, LLC (PJM) entered into an agreement that provides for, subject to regulatory approval and certain provisions, Dominion to become a member of PJM, transfer functional control of its electric transmission facilities to PJM for inclusion in a new PJM South Region and integrate its control area into the PJM energy markets. The agreement also allocates costs of implementation of the agreement among the parties.

In October 2004, the FERC issued an order conditionally approving Dominion’s application to join PJM. In its order, FERC determined that: (i) Dominion’s proposed transmission rate treatment must conform to a regional transmission rate design, and (ii) Dominion must assess all available evidence and determine whether the requested deferral of expenditures related to the establishment and operation of an RTO should be recorded as a regulatory asset until the end of the Virginia retail rate cap period. In a separate order issued in September 2004, FERC granted authority to Dominion subsidiaries with market based rate authority to charge market based rates for sales of electric energy and capacity to loads located within Dominion’s service territory upon its integration into PJM.

Dominion has made filings with both the Virginia Commission and North Carolina Utilities Commission (North Carolina

 

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Commission) requesting authorization to become a member of PJM. In October 2004, Dominion filed a settlement agreement with the Virginia Commission resolving most of the issues raised by interested parties in the proceeding, and hearings were held to address the remaining issues. The Virginia Commission approved Dominion’s application to join PJM in November 2004 subject to the terms and conditions of the settlement agreement. The North Carolina Commission evidentiary hearing was held in January 2005. Dominion cannot predict the outcome of this matter at this time.

 

North Carolina Rate Matter

In connection with the North Carolina Commission’s approval of the CNG acquisition, Dominion agreed not to request an increase in North Carolina retail electric base rates before 2006, except for certain events that would have a significant financial impact on Dominion’s electric utility operations. Fuel rates are still subject to change under the annual fuel cost adjustment proceedings. However, in April 2004, the North Carolina Commission commenced an investigation into Dominion’s North Carolina base rates and subsequently ordered Dominion to file a general rate case to show cause why its North Carolina base rates should not be reduced. The rate case was filed in September 2004 and in February 2005, Dominion reached a tentative settlement with parties in the case that is subject to North Carolina Commission approval before becoming effective.

 

Dominion Transmission, Inc. (DTI) Rate Matter

At the request of the Public Service Commission of the State of New York (PSCNY), DTI has engaged in negotiations with PSCNY regarding the potential for a prospective reduction of DTI ‘s transportation and storage service rates to address concerns about the level of DTI’s earnings. As a result of these negotiations, DTI and PSCNY have reached an agreement in principle that establishes parameters for a potential rate settlement, which must be finalized by DTI and its customers. DTI is negotiating with its customers to reach a possible settlement agreement. The settlement parameters envision reduced rates to DTI’s customers and a five-year moratorium on future changes to DTI’s transportation and storage service rates. If DTI is able to reach an agreement with its customers in the first quarter of 2005, FERC approval of a filed settlement could be obtained in the second quarter of 2005.

 

Recovery of Stranded Costs

Stranded costs are those generation-related costs incurred or commitments made by utilities under cost-based regulation that may not reasonably be expected to be recovered in a competitive market. At December 31, 2004, Dominion’s exposure to potentially stranded costs included long-term power purchase contracts that could ultimately be determined to be above market; generating plants that could possibly become uneconomical in a deregulated environment; and unfunded obligations for nuclear plant decommissioning and postretirement benefits not yet recognized in the financial statements. Dominion believes capped electric retail rates and, where applicable, wires charges will provide an opportunity to recover a portion of its potentially stranded costs, depending on market prices of electricity and other factors. Recovery of Dominion’s potentially stranded costs remains subject to numerous risks even in the capped-rate environment. These include, among others, exposure to long-term power purchase commitment losses, future environmental compliance requirements, changes in tax laws, nuclear decommissioning costs, inflation, increased capital costs and recovery of certain other items.

The enactment of deregulation legislation in 1999 not only caused the discontinuance of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation, for Dominion’s Virginia jurisdictional utility generation-related operations but also caused Dominion to review its utility generation assets for impairment and long-term power purchase contracts for potential losses at that time. Significant assumptions considered in that review included possible future market prices for fuel and electricity, load growth, generating unit availability and future capacity additions in Dominion’s market, capital expenditures, including those related to environmental improvements, and decommissioning activities. Based on those analyses, no recognition of plant impairments or contract losses was appropriate at that time. In response to future events resulting from the development of a competitive market structure in Virginia and the expiration or termination of capped rates and wires charges, Dominion may have to reevaluate its utility generation assets for impairment and long-term power purchase contracts for potential losses. Assumptions about future market prices for electricity represent a critical factor that affects the results of such evaluations. Since 1999, market prices for electricity have fluctuated significantly and will continue to be subject to volatility. Any such review in the future, which would be highly dependent on assumptions considered appropriate at the time, could possibly result in the recognition of plant impairment or contract losses that would be material to Dominion’s results of operations or its financial position.

Changes to Cost Structure—In April 2004, the Governor of Virginia signed into law amendments to the Virginia Restructuring Act and the Virginia fuel factor statute. The amendments extend capped base rates until December 31, 2010, unless capped rates are terminated earlier under the Virginia Restructuring Act. The generation-related cash flows provided by the Virginia Restructuring Act are intended to compensate Dominion for continuing to provide generation services and to allow Dominion to incur costs to restructure such operations during the transition period. As a result, during the transition period, Dominion’s earnings may increase to the extent that it can reduce operating costs for its utility generation-related operations. Conversely, the same risks affecting the recovery of Dominion’s stranded costs, discussed above, may also adversely impact its cost structure during the transition period. Accordingly, Dominion could realize the negative economic impact of any such adverse event. In addition to managing the cost of its generation-related operations, Dominion may also seek opportunities to sell available electric energy and capacity to customers beyond its electric utility service territory. Using cash flows from operations during the transition period, Dominion may further alter its cost structure or choose to make additional investment in its business.

The capped rates were derived from rates established as part of the 1998 Virginia rate settlement and do not provide for specific recovery of particular generation-related expenditures, except for

 

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certain regulatory assets. To the extent that Dominion manages its operations to reduce its overall operating costs below those levels included in the capped rates, Dominion’s earnings may increase. Since the enactment of the Virginia Restructuring Act, Dominion has been reviewing its cost structure to identify opportunities to reduce the annual operating expenses of its generation-related operations. In the period 2001 through 2004, Dominion negotiated the termination of several long-term power purchase agreements that is expected to reduce capacity payments in 2005 by $179 million.

 

Common Stock Dividend Increase

In July 2004, Dominion announced that its fourth-quarter dividend payable December 20, 2004, would be increased by 2 cents per share to 66.5 cents per share. In February 2005, the quarterly dividend rate increased again from 66.5 cents per share to 67 cents per share for an annual rate in 2005 of $2.68 per share. Dominion’s expected cash flow and earnings should enable it to make future annual increases when its board of directors deems it financially prudent. Common stock dividends are declared on a quarterly basis by the board of directors.

 

Statoil ASA (Statoil) Agreement

In June 2004, Dominion executed 20-year contracts with Statoil for the increased capacity planned for its Cove Point LNG facility and related gas transmission services. Under the terms of the agreements, Statoil will purchase firm LNG tanker discharge services and related transportation service from Cove Point, as well as downstream firm transportation and storage services from DTI. Plans call for increasing the Cove Point storage tank capacity to 14.6 bcf and the plant’s deliverability by 0.8 bcf per day to a total of 1.8 bcf per day. To provide the transmission services, Dominion also plans to expand its pipeline originating at Cove Point to deliver more natural gas to interstate pipeline connections in the Mid-Atlantic region as well as to build a pipeline and two compressor stations in central Pennsylvania. These projects are subject to regulatory approval and are expected to be placed in service in 2008.

 

Environmental Matters

Dominion is subject to costs resulting from a number of federal, state and local laws and regulations designed to protect human health and the environment. These laws and regulations affect future planning and existing operations. They can result in increased capital, operating and other costs as a result of compliance, remediation, containment and monitoring obligations. Historically, Dominion recovered such costs arising from regulated electric operations through utility rates. However, to the extent that environmental costs are incurred in connection with operations regulated by the Virginia Commission, during the period ending December 31, 2010, in excess of the level currently included in the Virginia jurisdictional electric retail rates, Dominion’s results of operations will decrease. After that date, recovery through regulated rates may be sought for only those environmental costs related to regulated electric transmission and distribution operations and recovery, if any, through the generation component of rates will be dependent upon the market price of electricity. Dominion also may seek recovery through regulated rates for environmental expenditures related to regulated gas transmission and distribution operations.

 

Environmental Protection and Monitoring Expenditures

Dominion incurred approximately $132 million, $113 million and $123 million of expenses (including depreciation) during 2004, 2003 and 2002, respectively, in connection with environmental protection and monitoring activities, and expects these expenses to be approximately $203 million in 2005 and $215 million in 2006. In addition, capital expenditures related to environmental controls were $94 million, $210 million and $280 million for 2004, 2003 and 2002, respectively. These expenditures are expected to be approximately $123 million for 2005 and $207 million for 2006. The 2005 and 2006 amounts include planned expenditures for the newly acquired USGen electric generating facilities.

 

Clean Air Act Compliance

The Clean Air Act requires Dominion to reduce its emissions of sulfur dioxide (SO2) and nitrogen oxide (NOX), which are gaseous by-products of fossil fuel combustion. The Clean Air Act’s SO2 and NOX reduction programs include:

  The issuance of a limited number of SO2 emission allowances. Each allowance permits the emission of one ton of SO2 into the atmosphere. The allowances may be transacted with a third party; and
  NOX emission limitations applicable during the ozone season months of May through September and on an annual average basis.

Implementation of projects to comply with SO2 and NOX limitations are ongoing and will be influenced by changes in the regulatory environment, availability of allowances, various state and federal control programs and emission control technology. In response to these requirements, Dominion estimates it will make capital expenditures at its affected generating facilities (including the newly acquired electric generating facilities from USGen) of approximately $700 million during the period 2005 through 2009 for SO2 and NOx emission control equipment.

 

Other EPA Matters

In relation to a Notice of Violation received by Virginia Power in 2000 from the EPA, Dominion entered into a Consent Decree settlement in 2003 and committed to improve air quality. Dominion has already incurred certain capital expenditures for environmental improvements at its coal-fired stations in Virginia and West Virginia. Dominion continues to commit to additional measures in its current financial plans and capital budget to satisfy the requirements of the Consent Decree.

 

Other

As part of its review of Dominion’s request related to the reissuance of a pollution discharge elimination permit for the Millstone Power Station, the Connecticut Department of Environmental Protection is evaluating the ecological impacts of the cooling water intake system. Until the permit is reissued, it is not possible to predict the financial impact that may result.

In October 2003, the EPA and the Massachusetts Department of Environmental Protection jointly issued a new National Pollutant Discharge Elimination System permit for the USGen, Brayton Point Power Station. The new permit contained conditions that in effect

 

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require the installation of cooling towers to address concerns over the withdrawal and discharge of cooling water. In November 2003, an appeal was filed with the EPA Environmental Appeals Board and the Division of Administrative Law Appeals in Massachusetts. Until the appeals process is completed, the outcome cannot be predicted.

 

Future Environmental Regulations

In January 2004, the EPA proposed additional regulations addressing pollution transport from electric generating plants as well as the regulation of mercury and nickel emissions. These regulatory actions, in addition to revised regulations to address regional haze, are expected to be finalized in 2005 and could require additional reductions in emissions from Dominion’s fossil fuel-fired generating facilities. If these new emission reduction requirements are imposed, significant additional expenditures may be required.

The U.S. Congress is considering various legislative proposals that would require generating facilities to comply with more stringent air emissions standards. Emission reduction requirements under consideration would be phased in under a variety of periods of up to 15 years. If these new proposals are adopted, additional significant expenditures may be required.

In 1997, the United States signed an international Protocol to limit man-made greenhouse emissions under the United Nations Framework Convention on Climate Change. However, the Protocol will not become binding unless approved by the U.S. Senate. Currently, the Bush Administration has indicated that it will not pursue ratification of the Protocol and has set a voluntary goal of reducing the nation’s greenhouse gas emission intensity by 18% over the next 10 years. Several legislative proposals that include provisions seeking to impose mandatory reductions of greenhouse gas emissions are under consideration in the United States Congress. Several Northeast states have already or are considering the imposition of mandatory carbon dioxide (CO2) reductions through the development of a regional cap-and-trade program. The cost of compliance with the Protocol or other mandatory greenhouse gas reduction obligations could be significant. Given the highly uncertain outcome and timing of future action, if any, by the U.S. federal government on this issue, Dominion cannot predict the financial impact of future climate change actions on its operations at this time.

 

Other Matters

USGen Power Stations

In January 2005, Dominion closed on its purchase of three electric power generation facilities from USGen for $642 million. The acquisition was part of a bankruptcy court-approved divestiture of generation assets by USGen. The plants include the 1,521-megawatt Brayton Point Station in Somerset, Massachusetts; the 743-megawatt Salem Harbor Station in Salem, Massachusetts; and the 426- megawatt Manchester Street Station in Providence, Rhode Island. These assets will be included in the Dominion Generation operating segment. Dominion did not acquire any of the facilities’ debt in the transaction and plans to finance the acquisition with a combination of debt and equity.

 

Kewaunee Nuclear Power Plant

During the fourth quarter of 2003, Dominion announced an agreement with Wisconsin Public Service Corporation, a subsidiary of WPS Resources Corporation (WPS), and Wisconsin Power & Light Company (WP&L), a subsidiary of Alliant Energy Corporation, to purchase the Kewaunee nuclear power plant , located in northeastern Wisconsin. Under terms of the agreement, the aggregate purchase price is $220 million in cash, including $35 million for nuclear fuel. Dominion will sell 100% of the facility’s output to WPS (59%) and WP&L (41%) under a power purchase agreement that expires in 2013. In November 2004, the Public Service Commission of Wisconsin voted to deny the sale. The transaction had received all other applicable regulatory approvals. During January 2005, the commission granted Dominion’s request for a rehearing of the case. If approved by the commission, the transaction is expected to close in the first half of 2005. If approved, Kewaunee would be included in the Dominion Generation operating segment.

 

Restructuring of Contract with Non-Utility Generator

In February 2005, Dominion paid $42 million in cash and assumed $62 million of debt in connection with the termination of a long-term power purchase agreement and acquisition of the related generating facility used by Panda-Rosemary LP, a non-utility generator, to provide electricity to Dominion. The transaction is part of an ongoing program that seeks to achieve competitive cost structures at Dominion’s utility generation business and is expected to reduce annual capacity payments by $18 million. The purchase price for the acquisition was allocated to the assets and liabilities acquired based on their estimated fair values as of the date of acquisition. In connection with the termination of the agreement, Dominion expects to record an after-tax charge of approximately $46 million.

 

Long-Term Power Tolling Contract

In the fourth quarter of 2004, Dominion recorded a $112 million after-tax charge related to its interest in a long-term power tolling contract with a 551 megawatt combined cycle facility located in Batesville, Mississippi. Dominion decided to divest its interest in the long-term power tolling contract in connection with its reconsideration of the scope of certain activities of the Clearinghouse, including those conducted on behalf of Dominion’s business segments, and its ongoing strategy to focus on business activities within the MAIN to Maine region. The charge is based on Dominion’s evaluation of preliminary bids received from third parties, reflecting the expected amount of consideration that would be required by a third party for its assumption of Dominion’s interest in the contract in the first quarter of 2005.

 

Future Acquisitions

In 2005, Dominion expects to focus on managing its existing assets rather than acquiring new assets through mergers or acquisitions. Exceptions would include acquiring a Midwest, Northeast or Mid-Atlantic nuclear station; replacing gas and oil reserves through acquisitions if more cost effective than drilling; or continuing to buy out uneconomic long-term power purchase agreements.

 

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Market Rate Sensitive Instruments and Risk Management

Dominion’s financial instruments, commodity contracts and related derivative financial instruments are exposed to potential losses due to adverse changes in interest rates, equity security prices, foreign currency exchange rates and commodity prices. Interest rate risk generally is related to Dominion’s outstanding debt. Commodity price risk is present in Dominion’s electric operations, gas and oil production and procurement operations, and energy marketing and trading operations due to the exposure to market shifts in prices received and paid for natural gas, electricity and other commodities. Dominion uses derivative commodity contracts to manage price risk exposures for these operations. In addition, Dominion is exposed to equity price risk through various portfolios of equity securities.

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

 

Commodity Price Risk—Trading Activities

As part of its strategy to market energy and to manage related risks, Dominion manages a portfolio of commodity-based derivative instruments held for trading purposes. These contracts are sensitive to changes in the prices of natural gas, electricity and certain other commodities. Dominion uses established policies and procedures to manage the risks associated with these price fluctuations and uses derivative instruments, such as futures, forwards, swaps and options, to mitigate risk by creating offsetting market positions.

A hypothetical 10% unfavorable change in commodity prices would have resulted in a decrease of approximately $23 million and $56 million in the fair value of Dominion’s commodity-based financial derivative instruments held for trading purposes as of December 31, 2004 and 2003, respectively.

 

Commodity Price Risk—Non-Trading Activities

Dominion manages the price risk associated with purchases and sales of natural gas, oil and electricity by using derivative commodity instruments including futures, forwards, options and swaps. For sensitivity analysis purposes, the fair value of Dominion’s non-trading derivative commodity instruments is determined based on models that consider the market prices of commodities in future periods, the volatility of the market prices in each period, as well as the time value factors of the derivative instruments. Market prices and volatility are principally determined based on quoted prices on the futures exchange. A hypothetical 10% unfavorable change in market prices of Dominion’s non-trading commodity-based financial derivative instruments would have resulted in a decrease in fair value of approximately $576 million and $424 million as of December 31, 2004 and December 31, 2003, respectively.

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

 

Interest Rate Risk

Dominion manages its interest rate risk exposure predominantly by maintaining a balance of fixed and variable rate debt. Dominion also enters into interest rate sensitive derivatives, including interest rate swaps and interest rate lock agreements. For financial instruments outstanding at December 31, 2004, a hypothetical 10% increase in market interest rates would decrease annual earnings by approximately $10 million. A hypothetical 10% increase in market interest rates, as determined at December 31, 2003, would have resulted in a decrease in annual earnings of approximately $6 million.

In addition, Dominion, through subsidiaries, retains ownership of mortgage investments, including subordinated bonds and interest-only residual assets retained from securitizations of mortgage loans originated and purchased in prior years. Note 26 to the Consolidated Financial Statements discusses the impact of changes in value of these investments.

 

Foreign Currency Exchange Risk

Dominion’s Canadian natural gas and oil exploration and production activities are relatively self-contained within Canada. As a result, Dominion’s exposure to foreign currency exchange risk for these activities is limited primarily to the effects of translation adjustments that arise from including that operation in its Consolidated Financial Statements. Dominion’s management monitors this exposure and believes it is not material. In addition, Dominion manages its foreign exchange risk exposure associated with anticipated future purchases of nuclear fuel processing services denominated in foreign currencies by utilizing currency forward contracts. As a result of holding these contracts as hedges, Dominion’s exposure to foreign currency risk is minimal. A hypothetical 10% unfavorable change in relevant foreign exchange rates would have resulted in a decrease of approximately $13 million and $19 million in the fair value of currency forward contracts held by Dominion at December 31, 2004 and 2003, respectively.

 

Investment Price Risk

Dominion is subject to investment price risk due to marketable securities held as investments in decommissioning trust funds. In accordance with current accounting standards, these marketable securities are reported on the Consolidated Balance Sheets at fair value. Dominion recognized a net realized gain (net of investment income) on nuclear decommissioning trust investments of $51 million in 2004 and a net realized loss (net of investment income) of $10 million in 2003. Dominion recorded, in AOCI, net unrealized gains on decommissioning trust investments of $84 million and $263 million in 2004 and 2003, respectively.

Dominion also sponsors employee pension and other postretirement benefit plans that hold investments in trusts to fund benefit payments. To the extent that the values of investments held in these trusts decline, the effect will be reflected in Dominion’s recognition of the periodic cost of such employee benefit plans and the determination of the amount of cash to be contributed to the employee benefit plans. Dominion’s pension plans experienced net realized and unrealized gains of $453 million and $627 million in 2004 and 2003, respectively.

 

 

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Risk Management Policies

Dominion has operating procedures in place that are administered by experienced management to help ensure that proper internal controls are maintained. In addition, Dominion has established an independent function at the corporate level to monitor compliance with the risk management policies of all subsidiaries. Dominion maintains credit policies that include the evaluation of a prospective counterparty’s financial condition, collateral requirements where deemed necessary, and the use of standardized agreements that facilitate the netting of cash flows associated with a single counterparty. In addition, Dominion also monitors the financial condition of existing counterparties on an ongoing basis. Based on credit policies and the December 31, 2004 provision for credit losses, management believes that it is unlikely that a material adverse effect on its financial position, results of operations or cash flows would occur as a result of counterparty nonperformance.

 

Risk Factors and Cautionary Statements That May Affect Future Results

Factors that may cause actual results to differ materially from those indicated in any forward-looking statement include weather conditions; governmental regulations; cost of environmental compliance; inherent risk in the operation of nuclear facilities; fluctuations in energy-related commodities prices and the effect these could have on Dominion’s earnings, liquidity position and the underlying value of its assets; trading counterparty credit risk; capital market conditions, including price risk due to marketable securities held as investments in trusts and benefit plans; fluctuations in interest rates; changes in rating agency requirements or ratings; changes in accounting standards; collective bargaining agreements and labor negotiations; the risks of operating businesses in regulated industries that are subject to changing regulatory structures; changes to regulated gas and electric rates recovered by Dominion; receipt of approvals for and the timing of the closing dates for pending acquisitions; realization of expected business interruption insurance proceeds; the transfer of control over electric transmission facilities to a regional transmission organization; board approval of future dividends; political and economic conditions (including inflation and deflation); and completing the divestiture of investments held by DCI. Other more specific risk factors are as follows:

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

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

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

Dominion is exposed to cost-recovery shortfalls because of capped base rates and amendments to the fuel factor statute in effect in Virginia for its regulated electric utility. Under the Virginia Restructuring Act, as amended in April 2004, Dominion’s base rates (excluding, generally, a fuel factor with limited adjustment provisions, and certain other allowable adjustments) remain unchanged until December 31, 2010 unless modified or terminated consistent with the Virginia Restructuring Act. Although the Virginia Restructuring Act allows for the recovery of certain generation-related costs during the capped rates periods, Dominion remains exposed to numerous risks of cost-recovery shortfalls. These include exposure to potentially stranded costs, future environmental compliance requirements, tax law changes, costs related to hurricanes or other weather events, inflation, the cost of obtaining replacement power during unplanned plant outages and increased capital costs. In addition, under the 2004 amendments to the Virginia fuel factor statute, Dominion’s current Virginia fuel factor provisions are locked-in until the earlier of July 1, 2007 or the termination of capped rates by order of the Virginia State Corporation Commission.

The amendments provide for a one-time adjustment of Dominion’s fuel factor, effective July 1, 2007 through December 31, 2010, with no adjustment for previously incurred over-recovery or under-recovery, thus eliminating deferred fuel accounting. As a result of the locked-in fuel factor and the uncertainty of what the one-time adjustment will be, Dominion is exposed to fuel price risk. This risk includes exposure to increased costs of fuel, including the energy portion of certain purchased power costs.

Under the Virginia Restructuring Act, the generation portion of Dominion’s electric utility operations is open to competition and resulting uncertainty. Under the Virginia Restructuring Act, the generation portion of Dominion’s electric utility operations in Virginia is open to competition and is no longer subject to cost-based regulation. To date, the competitive market has been slow to develop. Consequently, it is difficult to predict the pace at which the competitive environment will evolve and the

 

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extent to which Dominion will face increased competition and be able to operate profitably within this competitive environment.

Dominion’s merchant power business is operating in a challenging market which could adversely affect its results of operations and future growth. The success of Dominion’s approximately 9,700-megawatt merchant power business depends upon favorable market conditions as well as its ability to find buyers willing to enter into power purchase agreements at prices sufficient to cover operating costs. Dominion attempts to manage these risks by entering into both short-term and long-term fixed price sales and purchase contracts. However, depressed spot and forward wholesale power prices, high fuel and commodity costs and excess capacity in the industry could result in lower than expected revenues in Dominion’s merchant power business.

There are inherent risks in the operation of nuclear facilities. Dominion operates nuclear facilities that are subject to inherent risks. These include the threat of terrorist attack and ability to dispose of spent nuclear fuel, the disposal of which is subject to complex federal and state regulatory constraints. These risks also include the cost of and Dominion’s ability to maintain adequate reserves for decommissioning, costs of plant maintenance and exposure to potential liabilities arising out of the operation of these facilities. Dominion maintains decommissioning trusts and external insurance coverage to manage the financial exposure to these risks. However, it is possible that costs arising from claims could exceed the amount of any insurance coverage.

The use of derivative instruments could result in financial losses and liquidity constraints. Dominion uses derivative instruments, including futures, forwards, options and swaps, to manage its commodity and financial market risks. In addition, Dominion purchases and sells commodity-based contracts in the natural gas, electricity and oil markets for trading purposes. In the future, Dominion could recognize financial losses on these contracts as a result of volatility in the market values of the underlying commodities or if a counterparty fails to perform under a contract. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these contracts involves management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, Dominion uses financial derivatives to hedge future sales of its gas and oil production. These hedge arrangements generally include margin requirements that require Dominion to deposit funds or post letters of credit with counterparties to cover the fair value of covered contracts in excess of agreed upon credit limits. When commodity prices rise to levels substantially higher than the levels where it has hedged future sales, Dominion may be required to use a material portion of its available liquidity to cover these margin requirements. In some circumstances, this could have a compounding effect on Dominion’s financial liquidity and results.

For additional information concerning derivatives and commodity-based trading contracts, see Market Rate Sensitive Instruments and Risk Management and Notes 2 and 8 to the Consolidated Financial Statements.

Dominion is exposed to market risks beyond its control in its energy clearinghouse operations which could adversely affect its results of operations and future growth. Dominion’s energy clearinghouse and risk management operations are subject to multiple market risks including market liquidity, counterparty credit strength and price volatility. Many industry participants have experienced severe business downturns resulting in some companies exiting or curtailing their participation in the energy trading markets. This has led to a reduction in the number of trading partners and lower industry trading revenues. Declining creditworthiness of some of Dominion’s trading counterparties may limit the level of its trading activities with these parties and increase the risk that these parties may not perform under a contract.

Dominion’s exploration and production business is dependent on factors that cannot be predicted or controlled and that could damage facilities, disrupt production or reduce the book value of its assets. Factors that may affect Dominion’s financial results include weather that damages or causes the shutdown of its gas and oil producing facilities, fluctuations in natural gas and crude oil prices, results of future drilling and well completion activities and Dominion’s ability to acquire additional land positions in competitive lease areas, as well as inherent operational risks that could disrupt production.

Short-term market declines in the prices of natural gas and oil could adversely affect Dominion’s financial results by causing a permanent write-down of its natural gas and oil properties as required by the full cost method of accounting. Under the full cost method, all direct costs of property acquisition, exploration and development activities are capitalized. If net capitalized costs exceed the present value of estimated future net revenues based on hedge-adjusted period-end prices from the production of proved gas and oil reserves (the ceiling test) in a given country at the end of any quarterly period, then a permanent write-down of the assets must be recognized in that period.

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

 

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Changing rating agency requirements could negatively affect Dominion’s growth and business strategy. As of February 1, 2005, Dominion’s senior unsecured debt is rated BBB+, negative outlook, by Standard & Poor’s and Baa1, stable outlook, by Moody’s. Both agencies have implemented more stringent applications of the financial requirements for various ratings levels. In order to maintain its current credit ratings in light of these or future new requirements, Dominion may find it necessary to take steps or change its business plans in ways that may adversely affect its growth and earnings per share. A reduction in Dominion’s credit ratings or the credit ratings of its Virginia Power and CNG subsidiaries by either Standard & Poor’s or Moody’s could increase Dominion’s borrowing costs and adversely affect operating results and could require it to post additional margin in connection with some of its trading and marketing activities.

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

Failure to retain and attract key executive officers and other skilled professional and technical employees could have an adverse effect on the operations of Dominion. Implementation of Dominion’s growth strategy is dependent on its ability to recruit, retain and motivate employees. Competition for skilled employees in some areas is high and the inability to retain and attract these employees could adversely affect Dominion’s business and future financial condition.

 

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

See Risk Factors and Cautionary Statements That May Affect Future Results and Market Rate Sensitive Instruments and Risk Management in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

 

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Item 8. Financial Statements and Supplementary Data

Index

 

       Page No.

Management’s Annual Report on Internal Control over Financial Reporting

     48

Reports of Independent Registered Public Accounting Firm

     49

Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002

     51

Consolidated Balance Sheets at December 31, 2004 and 2003

     52

Consolidated Statements of Common Shareholders’ Equity and Comprehensive Income at December 31, 2004, 2003 and 2002 and for the years then ended

     54

Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002

     55

Notes to Consolidated Financial Statements

     56

 

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Management’s Annual Report on Internal Control over Financial Reporting

 

Management of Dominion Resources, Inc. (Dominion) understands and accepts responsibility for its financial statements and related disclosures and the effectiveness of internal control over financial reporting (internal control). Dominion continuously strives to identify opportunities to enhance the effectiveness and efficiency of internal control, just as it does throughout all aspects of its business.

Management maintains a system of internal control designed to provide reasonable assurance, at a reasonable cost, that Dominion’s and its subsidiaries’ assets are safeguarded against loss from unauthorized use or disposition and that transactions are executed and recorded in accordance with established procedures. This system includes written policies, an organizational structure designed to ensure appropriate segregation of responsibilities, careful selection and training of qualified personnel and internal audits.

The Audit Committee of the Board of Directors of Dominion, composed entirely of independent directors, meets periodically with the independent registered public accounting firm, the internal auditors and management to discuss auditing, internal control, and financial reporting matters of Dominion and to ensure that each is properly discharging its responsibilities. Both the independent registered public accounting firm and the internal auditors periodically meet alone with the Audit Committee and have free access to the Committee at any time.

SEC rules implementing Section 404 of the Sarbanes-Oxley Act of 2002 require Dominion’s 2004 Annual Report to contain a management’s report and a report of the independent registered public accounting firm regarding the effectiveness of internal control. As a basis for management’s report, Dominion tested and evaluated the design and operating effectiveness of internal controls. Based on its assessment as of December 31, 2004, Dominion makes the following assertion:

Management is responsible for establishing and maintaining effective internal control over financial reporting of Dominion.

There are inherent limitations in the effectiveness of any internal control, including the possibility of human error and the circumvention or overriding of controls. Accordingly, even effective internal controls can provide only reasonable assurance with respect to financial statement preparation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

On December 31, 2003, Dominion adopted Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, for its interests in special purpose entities, referred to as SPEs. As a result, Dominion has included in its consolidated financial statements certain SPEs. The Consolidated Balance Sheet, as of December 31, 2004, reflects $621 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to these SPEs. As these SPEs are owned by unrelated parties, Dominion does not have the authority to dictate or modify, and therefore could not assess the internal controls in place at these entities. Management’s conclusion regarding the effectiveness of Dominion’s internal control does not extend to the internal controls of these SPEs.

Management evaluated Dominion’s internal control over financial reporting as of December 31, 2004. This assessment was based on criteria for effective internal control over financial reporting described in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management believes that Dominion maintained effective internal control over financial reporting as of December 31, 2004.

The independent registered public accounting firm that audited the financial statements has issued an attestation report on Dominion’s assessment of the internal control over financial reporting.

 

February 28, 2005

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

 

We have audited the accompanying consolidated balance sheets of Dominion Resources, Inc. and subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related consolidated statements of income, common shareholders’ equity and comprehensive income, and of cash flows for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Dominion Resources, Inc. and subsidiaries as of December 31, 2004 and 2003, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 3 to the consolidated financial statements, in 2003 the Company changed its methods of accounting to adopt new accounting standards for: asset retirement obligations, contracts involved in energy trading, derivative contracts not held for trading purposes, derivative contracts with a price adjustment feature, the consolidation of variable interest entities, and guarantees.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Company’s internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2005, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

/s/ Deloitte & Touche LLP

 

Richmond, Virginia

February 28, 2005

 

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

 

To the Shareholders and Board of Directors of

Dominion Resources, Inc.

Richmond, Virginia

 

We have audited management’s assessment, included in paragraphs 5-9 of the accompanying Management’s Annual Report on Internal Control over Financial Reporting, that Dominion Resources, Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As described in Management’s Annual Report on Internal Control over Financial Reporting, management excluded from their assessment the internal control over financial reporting at certain special purpose entities consolidated under Financial Accounting Standards Board Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities. The Company’s Consolidated Balance Sheet, as of December 31, 2004, reflects $621 million of net property, plant and equipment and deferred charges and $688 million of related debt attributable to these special purpose entities. As these special purpose entities are owned by unrelated parties, the Company does not have the authority to dictate or modify, and therefore could not assess the internal controls in place at these entities. Accordingly, our audit did not include the internal control over financial reporting at those special purpose entities. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2004 of the Company and our reports dated February 28, 2005, expressed an unqualified opinion on those financial statements and financial statement schedule.

 

/s/ Deloitte & Touche LLP

 

Richmond, Virginia

February 28, 2005

 

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Consolidated Statements of Income

 

Year Ended December 31,      2004        2003        2002
(millions, except per share amounts)                         

Operating Revenue

     $ 13,972        $ 12,078        $ 10,218

Operating Expenses

                              

Electric fuel and energy purchases, net

       2,162          1,667          1,447

Purchased electric capacity

       587          607          691

Purchased gas, net

       2,927          2,175          1,159

Liquids, pipeline capacity and other purchases

       1,007          468          159

Other operations and maintenance

       2,748          2,908          2,190

Depreciation, depletion and amortization

       1,305          1,216          1,258

Other taxes

       519          476          429

Total operating expenses

       11,255          9,517          7,333

Income from operations

       2,717          2,561          2,885

Other income (loss)

       186          (40 )        103

Interest and related charges:

                              

Interest expense

       811          849          826

Interest expense—junior subordinated notes payable to affiliated trusts

       112                  

Distributions—mandatorily redeemable trust preferred securities

                111          103

Subsidiary preferred dividends

       16          15          16

Total interest and related charges

       939          975          945

Income before income taxes

       1,964          1,546          2,043

Income tax expense

       700          597          681

Income from continuing operations before cumulative effect of changes in accounting principles

       1,264          949          1,362

Loss from discontinued operations (net of income tax benefit of $4 and expense of $15, in 2004 and 2003, respectively)

       (15 )        (642 )       

Cumulative effect of changes in accounting principles (net of income taxes of $7)

                11         

Net Income

     $ 1,249        $ 318        $ 1,362

Earnings Per Common Share—Basic:

                              

Income from continuing operations before cumulative effect of changes in accounting principles

     $ 3.84        $ 2.99        $ 4.85

Loss from discontinued operations

       (0.04 )        (2.02 )       

Cumulative effect of changes in accounting principles

                .03         

Net income

     $ 3.80        $ 1.00        $ 4.85

Earnings Per Common Share—Diluted:

                              

Income from continuing operations before cumulative effect of changes in accounting principles

     $ 3.82        $ 2.98        $ 4.82

Loss from discontinued operations

       (0.04 )        (2.01 )       

Cumulative effect of changes in accounting principles

                .03         

Net income

     $ 3.78        $ 1.00        $ 4.82

Dividends paid per common share

     $ 2.60        $ 2.58        $ 2.58

 

The accompanying notes are an integral part of the Consolidated Financial Statements.

 

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Consolidated Balance Sheets

 

At December 31,      2004        2003  
(millions)                  

ASSETS

                     

Current Assets

                     

Cash and cash equivalents

     $ 389        $ 126  

Customer accounts receivable (net of allowance of $43 and $51)

       2,585          2,308  

Other accounts receivable

       320          828  

Inventories:

                     

Materials and supplies

       328          296  

Fossil fuel

       180          154  

Gas stored

       385          420  

Derivative assets

       1,713          1,436  

Deferred income taxes

       594          240  

Prepayments

       157          202  

Other

       471          531  

Total current assets

       7,122          6,541  

Investments

                     

Available for sale securities

       335          413  

Nuclear decommissioning trust funds

       2,023          1,872  

Other

       810          802  

Total investments

       3,168          3,087  

Property, Plant and Equipment

                     

Property, plant and equipment

       38,663          37,107  

Accumulated depreciation, depletion and amortization

       (11,947 )        (11,257 )

Total property, plant and equipment, net

       26,716          25,850  

Deferred Charges and Other Assets

                     

Goodwill, net

       4,298          4,300  

Regulatory assets

       788          832  

Prepaid pension cost

       1,947          1,939  

Derivative assets

       705          402  

Other

       702          595  

Total deferred charges and other assets

       8,440          8,068  

Total assets

     $ 45,446        $ 43,546  

 

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At December 31,      2004        2003  
(millions)                  

LIABILITIES AND SHAREHOLDERS’ EQUITY

                     

Current Liabilities

                     

Securities due within one year

     $ 1,368        $ 1,252  

Short-term debt

       573          1,452  

Accounts payable, trade

       1,984          1,929  

Accrued interest, payroll and taxes

       578          619  

Derivative liabilities

       2,858          2,082  

Other

       695          750  

Total current liabilities

       8,056          8,084  
Long-Term Debt                      

Long-term debt

       14,078          14,336  

Junior subordinated notes payable to affiliated trusts

       1,429          1,440  

Total long-term debt

       15,507          15,776  
Deferred Credits and Other Liabilities                      

Deferred income taxes

       5,424          4,614  

Deferred investment tax credits

       75          92  

Asset retirement obligations

       1,705          1,651  

Derivative liabilities

       1,583          1,185  

Regulatory liabilities

       610          587  

Other

       803          762  

Total deferred credits and other liabilities

       10,200          8,891  

Total liabilities

       33,763          32,751  

Commitments and Contingencies (see Note 22)

                     

Subsidiary Preferred Stock Not Subject To Mandatory Redemption

       257          257  
Common Shareholders’ Equity                      

Common stock—no par(1)

       10,888          10,052  

Other paid-in capital

       92          61  

Retained earnings

       1,442          1,054  

Accumulated other comprehensive loss

       (996 )        (629 )

Total common shareholders’ equity

       11,426          10,538  

Total liabilities and shareholders’ equity

     $ 45,446        $ 43,546  

 

(1)   500 million shares authorized; 340 million shares and 325 million shares outstanding at December 31, 2004 and December 31, 2003, respectively.

 

The accompanying notes are an integral part of the Consolidated Financial Statements.

 

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Consolidated Statements of Common Shareholders’ Equity and Comprehensive Income

 

     Common Stock     Other
Paid-In
Capital
    Retained
Earnings
    Accumulated
Other
Comprehensive
Income (Loss)
   

Total

 
     Shares     Amount          

(millions)

                                              

Balance at December 31, 2001

   265     $ 7,129     $ 28     $ 922     $ 289     $ 8,368  

Comprehensive income:

                                              

Net income

                           1,362               1,362  

Net deferred losses on derivatives—hedging activities, net of $345 tax benefit

                                   (663 )     (663 )

Unrealized losses on investment securities, net of $41 tax benefit

                                   (68 )     (68 )

Foreign currency translation adjustments

                                   6       6  

Minimum pension liability adjustment, net of $1 tax benefit

                                   (2 )     (2 )

Amounts reclassified to net income:

                                              

Net derivative gains—hedging activities, net of $4 tax expense

                                   (8 )     (8 )

Total comprehensive income

                           1,362       (735 )     627  

Issuance of stock—public offering

   38       1,712                               1,712  

Issuance of stock—employee and direct stock purchase plans

   3       199                               199  

Stock awards and stock options exercised (net of change in unearned compensation)

   3       113                               113  

Stock repurchase and retirement

   (1 )     (66 )                             (66 )

Accrued contract payments—equity-linked securities

           (36 )                             (36 )

Tax benefit from stock awards and stock options exercised

                   21                       21  

Dividends and other adjustments

                   (2 )     (723 )             (725 )

Balance at December 31, 2002

   308       9,051       47       1,561       (446 )     10,213  

Comprehensive income:

                                              

Net income

                           318               318  

Net deferred derivative losses—hedging activities, net of $479 tax benefit

                                   (791 )     (791 )

Unrealized gains on investment securities, net of $78 tax expense

                                   112       112  

Foreign currency translation adjustments

                                   68       68  

Amounts reclassified to net income:

                                              

Net realized losses on investment securities, net of $29 tax benefit

                                   49       49  

Net losses on derivatives—hedging activities, net of $225 tax benefit

                                   379       379  

Total comprehensive income

                           318       (183 )     135  

Issuance of stock—public offering

   11       683                               683  

Issuance of stock—employee and direct stock purchase plans

   3       206                               206  

Stock awards and stock options exercised (net of change in unearned compensation)

   3       112                               112  

Tax benefit from stock awards and stock options exercised

                   14                       14  

Dividends

                           (825 )             (825 )

Balance at December 31, 2003

   325       10,052       61       1,054       (629 )     10,538  

Comprehensive income:

                                              

Net income

                           1,249               1,249  

Net deferred derivative losses—hedging activities, net of $632 tax benefit

                                   (1,118 )     (1,118 )

Unrealized gains on investment securities, net of $18 tax expense

                                   37       37  

Foreign currency translation adjustments

                                   30       30  

Amounts reclassified to net income:

                                              

Net realized losses on investment securities, net of $12 tax benefit

                                   23       23  

Net losses on derivatives—hedging activities, net of $407 tax benefit

                                   705       705  

Foreign currency translation adjustments(1)

                                   (44 )     (44 )

Total comprehensive income

                           1,249       (367 )     882  

Issuance of stock—equity-linked securities

   7       413                               413  

Issuance of stock—employee and direct stock purchase plans

   3       206                               206  

Stock awards and stock options exercised (net of change in unearned compensation)

   5       223                               223  

Cash settlement—forward equity transaction

           (6 )                             (6 )

Tax benefit from stock awards and stock options exercised

                   31                       31  

Dividends

                           (861 )             (861 )

Balance at December 31, 2004

   340     $ 10,888     $ 92     $ 1,442     $ (996 )   $ 11,426  

(1) Reclassified to earnings due to the sale of CNG International investments.

 

The accompanying notes are an integral part of the Consolidated Financial Statements.

 

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Consolidated Statements of Cash Flows

 

Year Ended December 31,      2004        2003