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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2005

or

For the transition period from              to             

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact Name of Registrant as Specified in Its Charter)

(804) 747-0592

(Registrant’s Telephone Number, Including Area Code)

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 whether the Registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).    Yes  ¨    No  x

The Registrant is a membership corporation and has no authorized or outstanding equity securities.

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OLD DOMINION ELECTRIC COOPERATIVE

INDEX

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OLD DOMINION ELECTRIC COOPERATIVE

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

The accompanying notes are an integral part of the condensed consolidated financial statements.

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

The accompanying notes are an integral part of the condensed consolidated financial statements.

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOW (UNAUDITED)

The accompanying notes are an integral part of the condensed consolidated financial statements.

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

TEC was formed in 2001 for the primary purpose of purchasing from us, to sell in the market, power that is not needed to meet the actual needs of our member distribution cooperatives, acquiring natural gas and forward purchase contracts to hedge the price of natural gas to supply our combustion turbine facilities, and taking advantage of other power-related trading opportunities in the market which will help lower our member distribution cooperatives’ costs. TEC does not engage in speculative trading. TEC is a taxable corporation and a provision for income taxes has been established based upon TEC’s pre-tax income using statutory tax rates of 35% for federal purposes and 4% for state purposes.

In accordance with Financial Accounting Standards Board Interpretation No. 46R, “Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”), TEC is considered a variable interest entity for which we are the primary beneficiary. We became the primary beneficiary of TEC in 2001. We first consolidated TEC’s financial position as of December 31, 2004, and beginning January 1, 2005, TEC’s operations were also consolidated as a result of the adoption of the Interpretation. We have eliminated all balances and transactions in consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the net assets consolidated were $22.8 million and $10.2 million at March 31, 2005, and December 31, 2004, respectively. As TEC is 100% owned by our twelve member distribution cooperatives, its equity is presented as a non-controlling interest in our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities is recorded using the equity method of accounting.

Our rates are not regulated by the respective states’ public service commissions, but are set periodically by a formula that was accepted for filing by the Federal Energy Regulatory Commission (“FERC”) on December 23, 2003. An amendment to the formula was accepted for filing by FERC on February 19, 2005, subject to the outcome of our other pending FERC proceedings.

We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with accounting principles generally accepted in the United States (“GAAP”), the accounting policies and practices applied by us in the determination of rates are also employed for financial reporting purposes.

The preparation of our consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported therein. Actual results could differ from those estimates.

Our investments in marketable securities, which are actively managed, are classified as available for sale and are recorded at fair value. Unrealized gains or losses on these investments, if material, are reflected as a component of capitalization. Investments in debt securities that we have the positive intent and ability to hold to maturity are classified as held to maturity and are recorded at amortized cost. Other investments are recorded at cost, which approximates market value.

We primarily purchase power under both long-term and short-term forward physical delivery contracts to supply power to our member distribution cooperatives under “all requirements” wholesale power contracts. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of the forward purchase derivative contracts qualify for the normal purchases/normal sales exception under Statement of Financial Accounting Standards (“SFAS”) No. 133 “Accounting for

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Derivative Instruments and Hedging Activities.” As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the forward physical delivery contract is delivered. We also purchase natural gas futures generally for two years or less to hedge the price of natural gas for the operation of our combustion turbine facilities and for use as a basis in determining the price of power in certain forward power purchase agreements. These derivatives do not qualify for the normal purchases/normal sales exception.

For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we may elect cash flow hedge accounting in accordance with SFAS No. 133. Accordingly, gains and losses on derivative contracts are deferred into Other Comprehensive Income until the hedged underlying transaction occurs or is no longer likely to occur. For derivative contracts where hedge accounting is not utilized, or for which ineffectiveness exists, we defer all remaining gains and losses on a net basis as a regulatory asset or liability in accordance with SFAS No. 71 “Accounting for the Effects of Certain Types of Regulation.” These amounts are subsequently reclassified as purchased power or fuel expense in our Consolidated Statements of Revenues, Expenses, and Patronage Capital as the power or fuel is delivered and/or the contract settles.

Generally, derivatives are reported on the Consolidated Balance Sheet at fair value. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. There was no hedge ineffectiveness during the quarter ended March 31, 2005, or the year ended December 31, 2004.

During the discovery phase of the trial, RBI revised its claim from $15.0 million to $33.0 million. We have reviewed the asserted claims of RBI and believe they are without merit. We do not believe any liability is estimable or probable and we intend to vigorously defend these claims.

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Caution Regarding Forward-Looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors that could cause actual results to differ materially from those expressed in the forward-looking statements. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, increased competition in the electric utility industry, changes in our tax status, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, weather conditions, the cost of commodities used in our industry, and unanticipated changes in operating expenses and capital expenditures. Our actual results may vary materially from those discussed in the forward-looking statements as a result of these and other factors. Any forward-looking statement speaks only as of the date on which the statement is made, and we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which the statement is made even if new information becomes available or other events occur in the future.

Critical Accounting Policies

As of March 31, 2005, there have been no significant changes in our critical accounting policies as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2004. The policies included the accounting for rate regulation, deferred energy, asset retirement obligations, derivative contracts and our margin stabilization plan.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative (“Old Dominion” or “we” or “our”) and TEC Trading, Inc. (“TEC”) effective December 31, 2004. See Note 2—Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.

Overview

Old Dominion is a not-for-profit power supply cooperative owned entirely by its twelve member distribution cooperatives and a thirteenth member, TEC. We supply our member distribution cooperatives power requirements, consisting of capacity requirements and energy requirements through a portfolio of resources including generating facilities, power purchase contracts, and forward, short-term and spot market energy purchases.

Our results for the three months ended March 31, 2005, were primarily impacted by the following factors:

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Results of Operations

Operating Revenues

Our power sales are comprised of two power products – energy and capacity (also referred to as demand). Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as capacity.

The rates we charge our member distribution cooperatives for sales of energy and capacity are determined by a formulary rate accepted by the Federal Energy Regulatory Commission (“FERC”), which is intended to permit collection of revenues which will equal the sum of:

The formulary rate has three components: a demand rate, a base energy rate and a fuel factor adjustment rate. The formulary rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

Energy costs, which are primarily variable costs, such as nuclear, coal and natural gas fuel costs and the energy costs under our power purchase contracts with third parties, are recovered through two separate energy rates, the base energy rate and the fuel factor adjustment rate. The base energy rate is a fixed rate that requires FERC approval prior to adjustment. However, to the extent the base energy rate over- or under-collects all of our energy costs, we refund or collect the difference through a fuel factor adjustment rate. We review our energy costs at least every six months to determine whether the base energy rate and the current fuel factor adjustment rate together are adequately recovering our actual and anticipated energy costs, and revise the fuel factor adjustment rate accordingly. Because the fuel factor adjustment rate can be revised without FERC approval, we can effectively change our total energy rate to recover all our energy costs without seeking the approval of FERC.

Capacity costs, which are primarily fixed costs, such as depreciation expense, interest expense, administrative and general expenses, capacity costs under power purchase contracts with third parties, transmission costs, and our margin requirements and additional amounts approved by our board of directors are recovered through our demand rate. The formulary rate allows us to change the actual demand rate we charge as our capacity-related costs change, without seeking FERC approval, with the exception of extraordinary deductions, and decommissioning cost, which is a fixed amount in the formulary rate that requires FERC approval prior to any adjustment. As of December 23, 2003, decommissioning costs have been fixed at zero, reflecting our assessment that, based on current projections, our decommissioning trust fund is adequately funded. Our demand rate is revised automatically to recover the costs contained in our annual budget and any revisions made by our Board of Directors to our annual budget.

Our operating revenues are derived from power sales to our members and non-members. Sales to members include sales to our Class A members, which are our twelve member distribution cooperatives. Prior to January 1, 2005, sales to members included sales to our single Class B member, TEC. We consolidated TEC’s financial position as of December 31, 2004 and beginning January 1, 2005, TEC’s operations were also consolidated as a result of the adoption of the Interpretation. Sales between Old Dominion and TEC have been eliminated. TEC’s sales to third parties are reflected as non-member revenues. See Note 2 in Notes to the Condensed Consolidated

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Financial Statements in Part 1, Item 1. Our operating revenues by type of purchaser for the three months ended March 31, 2005 and 2004, were as follows:

Non-member revenues for 2005 include Old Dominion’s sales to TEC of $14.6 million, our sole Class B member, which now as a result of the consolidation of TEC are recorded as non-member sales.

Our energy sales in megawatt hours (“MWh”) to our members and non-members for the three months ended March 31, 2005 and 2004, were as follows:

Sales to Member Distribution Cooperatives. Revenues from sales to our member distribution cooperatives are a function of our formulary rate for sales of power to our member distribution cooperatives and our member distribution cooperatives’ consumers’ requirements for power. Operating revenues on our Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital reflect the actual capacity-related costs we incurred plus the energy costs that we collected during the quarter. Estimated capacity-related costs are collected during the period through the demand component of our formulary rate. Under our formulary rate, we make adjustments for the refund or recovery of amounts under our Margin Stabilization Plan. We adjust demand revenues and accounts payable – members or accounts receivable each quarter to reflect these adjustments. See “Critical Accounting Policies – Margin Stabilization Plan” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2004, for a discussion of the Margin Stabilization Plan.

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Revenues from sales to our member distribution cooperatives by formulary rate component and average costs to our member distribution cooperatives in MWh for the three months ended March 31, 2005 and 2004, were as follows:

Growth in the number of consumers and growth in consumers’ requirements for power significantly affect our member distribution cooperatives’ consumers’ requirements for power. Factors affecting our member distribution cooperatives’ consumers’ requirements for power include weather, as well as the amount, size, and usage of electronics and machinery and the expansion of operations among their commercial and industrial customers. Weather affects the requirement for electricity. Relatively higher or lower temperatures tend to increase the requirement for energy to operate air conditioning and heating systems. Mild weather generally reduces the requirement because air conditioning and heating systems are operated less.

Total revenues from sales to our member distribution cooperatives for the three months ended March 31, 2005, increased $20.7 million, or 15.6%, over the same period in 2004, primarily as a result of higher energy rates and slightly higher incurred capacity costs (which are reflected in revenues in the period in which they are expensed).

Our total energy rate (including our base energy rate and our fuel factor adjustment rate) was 22.5% higher during the three months ended March 31, 2005, as compared to the same period in 2004. We increased our fuel factor adjustment rate effective April 1, 2004, and October 1, 2004, resulting in an increase to our total energy rate of approximately 15.6% and 6.3%, respectively. These increases were implemented due to higher than anticipated energy costs in 2004 related to increased fuel and purchased power costs.

The capacity costs we incurred, and thus the capacity-related revenues we reflected pursuant to the formulary rate, for the three months ended March 31, 2005, as compared to the same period in 2004, increased $1.3 million, or 2.4%, primarily as a result of slightly higher depreciation and interest expense. Our Marsh Run combustion turbine facility (“Marsh Run”) became commercially operable in September 2004 and therefore we had depreciation expense related to Marsh Run for the three months ended March 31, 2005, but not for the three months ended March 31, 2004. For the three months ended March 31, 2004, costs for Marsh Run, including interest, were being capitalized. See “Interest Charges” for a discussion of interest expenses.

Our average costs to member distribution cooperatives per MWh increased $6.44 per MWh, or 13.8%, for the three months ended March 31, 2005, as compared to the same period in 2004, primarily as a result of the increase in our total energy rates related to increased fuel and purchased power costs.

Sales to TEC. Beginning January 1, 2005, we reported no sales to TEC because TEC is now consolidated as a result of the adoption of the Interpretation. Sales between Old Dominion and TEC have been eliminated in consolidation and TEC’s sales to third parties are reflected as non-member revenues. See Note 2 in the Notes to the Condensed Consolidated Financial Statements in Part 1, Item 1. Prior to January 1, 2005, sales to TEC consisted primarily of sales of excess energy that we did not need to meet the actual needs of our member distribution cooperatives. We sold the portion of this energy that could not be utilized by our member distribution cooperatives to TEC for resale into the market, or to non-members.

Sales to Non-Members. Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy. We primarily sell excess purchased energy to PJM under its rates for providing energy imbalance services. We sell excess energy from Clover to Virginia Power pursuant to the requirements of the Clover operating agreement. Beginning in 2005, TEC’s sales to third parties are also reflected as non-member revenue. Non-member revenue increased by $17.1 million in the first quarter of 2005 over the same period in 2004 primarily due to increased sales of excess energy. We had purchased forward energy products

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for delivery into the PJM control area with the expectation that Virginia Power would join PJM on January 1, 2005; however, due to a delay in regulatory approval, Virginia Power did not join PJM until May 1, 2005. Because of the delay in Virginia Power’s integration into PJM, much of our member distribution cooperatives’ capacity and energy requirements were still outside of the PJM control area. Although we could have arranged for this energy that was delivered to the PJM control area to subsequently be transmitted to our member distribution cooperatives’ outside of PJM, it was more economical at the time to sell this energy to non-members in the PJM markets and procure a similar amount of energy from other sources to deliver to our member distribution cooperatives.

Operating Expenses

We supply our member distribution cooperatives’ power requirements, consisting of capacity requirements and energy requirements, through (i) our owned or leased interests in electric generating facilities which consist of a 50% interest in Clover, an 11.6% interest in the North Anna Nuclear Power Station (“North Anna”), our Louisa combustion turbine facility (“Louisa”), Marsh Run, and our Rock Springs combustion turbine facility (“Rock Springs”), and distributed generation, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Our energy supply for the three months ended March 31, 2005 and 2004, was as follows:

We satisfy the majority of our member distribution cooperatives’ capacity requirements and a portion of their energy requirements through our ownership interests in Clover, North Anna, Louisa, Marsh Run and Rock Springs. We purchase capacity and energy from the market to supply the remaining needs of our member distribution cooperatives.

Our operating expenses are significantly affected by the extent to which we purchase power and, relatedly, the availability of our base load generating facilities, Clover and North Anna. Base load generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs, but nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities also have relatively low variable costs, as compared to combustion turbine facilities such as Louisa, Marsh Run, and Rock Springs. Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate. When either Clover or North Anna is off-line, we must purchase replacement energy from either Virginia Power, which is more costly, or from the market, which may be more or less costly. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but are more expensive to operate; therefore, we operate them only when the market price of energy makes their operation economical. As a result, our operating expenses, and consequently our rates to our member distribution cooperatives, are more significantly affected by the

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operations of Clover and North Anna than by our combustion turbine facilities. The output of Clover and North Anna for the three months ended March 31, 2005 and 2004, as a percentage of the maximum dependable capacity rating of the facilities was as follows:

Clover. Clover Unit 1 and Clover Unit 2 experienced minor unscheduled outages during the three months ended March 31, 2005, and March 31, 2004.

North Anna. North Anna Unit 1 and North Anna Unit 2 did not experience any outages during the three months ended March 31, 2005 or March 31, 2004.

Combustion turbine facilities. During the first quarter of 2005, the operational availability of our Louisa, Marsh Run and Rock Springs combustion turbine facilities was 100.0%, 100.0% and 95.6%, respectively. During the first quarter of 2004, the operational availability of our Louisa and Rock Springs combustion turbine facilities was 94.0% and 88.4%, respectively. Our Marsh Run combustion turbine facility became commercially operable on September 15, 2004.

The components of our operating expenses for the three months ended March 31, 2005 and 2004, were as follows:

Aggregate operating expenses increased $33.9 million, or 28.1%, for the three months ended March 31, 2005, as compared to the same period in 2004, primarily due to increases in fuel and purchased power expense, offset by a change in deferred energy.

Fuel expense increased $5.4 million, or 27.0%, for the three months ended March 31, 2005, as compared to the same period in 2004, primarily as a result of the 40.4% increase in the average cost of coal.

Purchased power expense increased $35.9 million, or 44.4%, for the three months ended March 31, 2005, as compared to the same period in 2004, due to a 22.6% increase in the volume of purchased power and an increase in the average cost of purchased power. The increase in the average cost of purchased power is reflective of the overall price increases in energy costs across all markets. The average cost of purchased power for the three months ended March 31, 2005, increased 17.7%, as compared to the same period in 2004.

Deferred energy expense changed $9.7 million, or 123.8%, for the three months ended March 31, 2005, as compared to the same period in 2004. During the first quarter of 2005, we under-collected $17.6 million in energy costs; whereas in the first quarter of 2004 when we had under-collected $7.9 million in energy costs. At March 31, 2005, we had an under-collected deferred energy balance of $12.8 million.

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On April 13, 2005, our Board of Directors approved an increase to the fuel factor adjustment rate, resulting in an increase to our total energy rate of approximately 14.6% effective April 1, 2005. This increase was implemented due to continued rising energy costs. Additionally, our Board of Directors approved a decrease in our demand rate of approximately 4.3%, effective April 1, 2005. This decrease was implemented due to an overall decline in fixed costs.

Other Items

Investment Income. Investment income increased by $0.3 million or 49.6% for the three months ended March 31, 2005, as compared to the same period in 2004, primarily due greater investment income earned on our nuclear decommissioning trust fund and interest associated with accounts payable – members.

Interest Charges, net. The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, issuance of new indebtedness and capitalized interest.

The major components of interest charges, net for the three months ended March 31, 2005 and 2004, were as follows:

Interest charges, net increased by $2.6 million, or 21.3%, for the three months ended March 31, 2005, as compared to the same period in 2004, primarily due to our reduction in capitalized interest associated with Marsh Run. We ceased capitalizing interest on Marsh Run in September 2004 when the facility became commercially operable. Capitalized interest is computed monthly using an interest rate which reflects our embedded cost of indebtedness, multiplied by our investment in projects under construction.

Net Margin. Our net margin, which is a function of our total interest charges, remained relatively flat for the three months ended March 31, 2005, as compared to the same period in 2004.

Financial Condition

The principal changes in our financial condition from December 31, 2004 to March 31, 2005, were caused by increases in non-controlling interest related to the consolidation of TEC, accounts payable—members, accrued expenses, deferred taxes, and the change in deferred energy. Non-controlling interest related to the consolidation of TEC increased $9.1 million, or 110.4%, from December 31, 2004, to March 31, 2005 due to the increase in unrealized gain on derivatives recorded on TEC’s financial statements due to a change in the market value of its contracts for delivery of gas in the future at specified prices. Accounts payable – members increased $11.9 million, or 30.9%, from December 31, 2004 to March 31, 2005, as a result of an increase in the amounts owed to our member distribution cooperatives under our Margin Stabilization Plan. Accrued expenses increased $16.0 million, or 109.9%, from December 31, 2004, to March 31, 2005, primarily due to the timing of interest payments. Deferred taxes increased $5.7 million, or 100%, due to the consolidation of TEC. Our deferred energy balance represents the net under- or over-collection of energy costs as of the end of the reporting period. These amounts are recovered from or refunded to our member distribution cooperatives in subsequent periods. The deferred energy balance changed from a $4.8 million liability (over-collection of costs) at December 31, 2004, to a $12.8 million asset (under-collection of costs) at March 31, 2005.

Liquidity and Capital Resources

Operations. Historically, our operating cash flows have been sufficient to meet our short- and long-term capital expenditures related to our existing generating facilities, our debt service requirements, and our ordinary business operations. Our operating activities provided cash flow of $32.4 million and $25.0 million during the first three month of 2005 and 2004, respectively. Operating activities were impacted primarily by changes in the first three months of 2005 in deferred energy, current liabilities and deferred charges and credits. At March 31, 2005, we

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had an under-collected deferred energy balance of $12.8 million as compared to an over-collected deferred energy balance of $4.8 million at December 31, 2004, which resulted in a cash outflow of $17.6 million. The change in current liabilities, which resulted in cash inflows of $21.5 million, is primarily related to the increase in accrued interest due to the timing of interest payments and the increase in the amounts owed to our member distribution cooperatives under our Margin Stabilization Plan. Deferred charges and credits increased, providing cash, primarily due to the unrealized gain on derivatives recorded on TEC’s financial statements due to a change in the market value of its contracts for the delivery of gas in the future at specified prices.

Financing Activities. In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term funding needs. As of March 31, 2005, we had short-term committed variable rate lines of credit in an aggregate amount of $230.0 million. Of this amount, $180.0 million was available for general working capital purposes and $50.0 million was available for capital expenditures related to our generating facilities. Additionally, we have a $50.0 million three-year revolving credit facility.

At March 31, 2005 and 2004, we had no short-term borrowings or letters of credit outstanding under any of these arrangements. We expect the working capital lines of credit to be renewed as they expire. We expect the construction-related line of credit to be renewed until such time as we determine it is not needed.

Investing Activities. Investing activities in the first three months of 2005 was primarily impacted by proceeds from the sale of available for sale securities, interest earned on investments-other and cash and cash equivalents, as well as electric plant additions for our generation facilities.

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ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2005.

ITEM 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer conducted an evaluation of the effectiveness of our disclosure controls and procedures. Based upon that evaluation, the President and Chief Executive Officer and Senior Vice President and Chief Financial Officer concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members from senior and middle management to assist in this evaluation. There have been no significant changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Ragnar Benson, Inc.

During the discovery phase of legal proceedings with Ragnar Benson, Inc. (“RBI”), RBI revised its claim from $15.0 million to $33.0 million. We have reviewed the asserted claims of RBI and believe they are without merit. We do not believe any liability is estimable or probable and we intend to vigorously defend these claims. For further description of our legal proceedings with RBI, see Part 1, Item 3 – Legal Proceedings in our 2004 Annual Report on Form 10-K.

Other Matters

No material developments have occurred in our legal proceedings with Norfolk Southern or the FERC Proceedings Related to Potential Reorganization since the filing of our Annual Report on Form 10-K for the fiscal year ended December 31, 2004. See Part 1, Item 3 – Legal Proceedings in our 2004 Annual Report on Form 10-K. Other than legal proceedings arising out of the ordinary course of business, which management believes will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

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ITEM 5.

OTHER INFORMATION

Virginia Power Joins PJM

On May 1, 2005, operational control of the Virginia Power’s transmission facilities was transferred to PJM. With this transfer, all of our member distribution cooperatives’ capacity and energy requirements are now within the PJM control area. Several changes occurred in connection with this transfer that impact us:

ITEM 6. EXHIBITS

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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EXHIBIT INDEX

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