Old Dominion Electric Cooperative 10-Q 2003 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2003

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 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact Name of Registrant as Specified in Its Charter)

VIRGINIA	23-7048405
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
4201 Dominion Boulevard, Glen Allen, Virginia	23060
(Address of Principal Executive Offices)	(Zip Code)

(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 the Exchange Act of Rule 12b-2).    Yes  ¨    No  x 

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

OLD DOMINION ELECTRIC COOPERATIVE

INDEX

		Page Number
PART I. Financial Information
Item 1.	Financial Statements
	Condensed Consolidated Balance Sheets – September 30, 2003 (Unaudited) and December 31, 2002	3
	Condensed Consolidated Statements of Revenues, Expenses and Patronage Capital (Unaudited) – Three and Nine Months Ended September 30, 2003 and 2002	4
	Condensed Consolidated Statements of Comprehensive Income (Unaudited) - Three and Nine Months Ended September 30, 2003 and 2002	4
	Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine Months Ended September 30, 2003 and 2002	5
	Notes to Condensed Consolidated Financial Statements	6
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	9
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	17
Item 4.	Controls and Procedures	17
PART II. Other Information
Item 1.	Legal Proceedings	18
Item 6.	Exhibits and Reports on Form 8-K	18
Signature		19

OLD DOMINION ELECTRIC COOPERATIVE

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2003			December 31, 2002*
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
In service	$	1,293,798		$	926,805
Less accumulated depreciation		(389,469	)		(364,653	)
		904,329			562,152
Nuclear fuel, at amortized cost		8,493			4,226
Construction work in progress		149,678			371,708
Net Electric Plant		1,062,500			938,086
Investments:
Nuclear decommissioning trust		63,897			56,684
Lease deposits		148,277			143,598
Other		244,802			77,936
Total Investments		456,976			278,218
Current Assets:
Cash and cash equivalents		30,091			67,829
Receivables		54,536			54,566
Fuel, materials and supplies, at average cost		19,033			11,467
Prepayments		3,284			2,154
Deferred energy		783			—
Total Current Assets		107,727			136,016
Deferred Charges:
Regulatory assets		59,022			65,883
Other		14,118			11,856
Total Deferred Charges		73,140			77,739
Total Assets	$	1,700,343		$	1,430,059
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	244,286		$	235,534
Accumulated other comprehensive income (loss)		—			(10,911	)
Long-term debt		1,002,663			750,682
Total Capitalization		1,246,949			975,305
Current Liabilities:
Long-term debt due within one year		11,913			11,913
Accounts payable		76,597			75,333
Accounts payable – members		40,837			59,944
Accrued expenses		52,666			35,249
Deferred energy		—			3,039
Deferred revenue		—			10,278
Total Current Liabilities		182,013			195,756
Deferred Credits and Other Liabilities
Asset retirement obligations		40,903			—
Decommissioning reserve		—			56,684
Obligations under long-term leases		151,270			146,465
Regulatory liabilities		34,757			1,303
Other		44,451			54,546
Total Deferred Credits and Other Liabilities		271,381			258,998
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	1,700,343		$	1,430,059

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

* The Condensed Consolidated Balance Sheet at December 31, 2002, has been taken from the audited financial statements at that date, but does not include all disclosures required by generally accepted accounting principles.

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES AND PATRONAGE CAPITAL (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in thousands)						(in thousands)
Operating Revenues	$	136,115		$	130,255		$	412,152		$	375,928
Operating Expenses:
Fuel		27,318			16,024			56,473			41,889
Purchased power		59,819			95,741			243,064			222,495
Deferred energy		5,766			(10,009	)		(3,822	)		23,290
Operations and maintenance		7,608			8,785			33,040			25,682
Administrative and general		6,946			5,928			18,813			16,660
Depreciation, amortization and decommissioning		8,304			5,986			19,129			17,687
Amortization of regulatory asset/(liability), net		1,733			(3,801	)		(844	)		(7,603	)
Taxes other than income taxes		1,057			854			2,720			2,561
Accretion		511			—			1,557			—
Total Operating Expenses		119,062			119,508			370,130			342,661
Operating Margin		17,053			10,747			42,022			33,267
Other Income/(Expense), net		172			(17	)		(82	)		714
Investment Income		453			461			1,938			2,467
Interest Charges, net		(14,410	)		(8,670	)		(31,855	)		(28,885	)
Net Margin Before Cumulative Effect of Change in Accounting Principle		3,268			2,521			12,023			7,563
Cumulative Effect of Change in Accounting Principle		—			—			(3,271	)		—
Net Margin After Cumulative Effect of Change in Accounting Principle		3,268			2,521			8,752			7,563
Patronage Capital – Beginning of Period		241,018			230,580			235,534			225,538
Patronage Capital – End of Period	$	244,286		$	233,101		$	244,286		$	233,101

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS

OF COMPREHENSIVE INCOME (UNAUDITED)

	Three Months Ended September 30,					Nine Months Ended September 30,
	2003		2002			2003		2002
	(in thousands)					(in thousands)
Net Margin	$	3,268	$	2,521		$	8,752	$	7,563
Other Comprehensive Income/(Loss):
Unrealized gain/(loss) on investments		—		34			—		(460	)
Cumulative effect of accounting change on derivative contracts		—		—			—		(15,944	)
Unrealized gain/(loss) on derivative contracts		—		(1,983	)		10,911		(1,024	)
Other comprehensive income/(loss)		—		(1,949	)		10,911		(17,428	)
Comprehensive Income/(Loss)	$	3,268	$	572		$	19,663	$	(9,865	)

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 FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2003			2002
	(in thousands)
Operating Activities:
Net Margin	$	8,752		$	7,563
Adjustments to reconcile net margins to net cash provided by operating activities:
Cumulative effect of change in accounting principle		3,271			—
Depreciation, amortization and decommissioning		19,129			17,687
Other non-cash charges		(978	)		6,978
Amortization of lease obligations		7,137			7,422
Interest on lease deposits		(6,811	)		(7,279	)
Change in current assets		(8,666	)		3,624
Change in deferred energy		(3,822	)		23,290
Change in current liabilities		(426	)		52,615
Change in regulatory assets and liabilities		(6,041	)		(9,231	)
Deferred charges and credits		621			3,926
Net Cash Provided by Operating Activities		12,166			106,595
Financing Activities:
Obligations under long-term leases		(200	)		(272	)
Additions of Long-term Debt		250,000			—
Net Cash Provided By (Used For) Financing Activities		249,800			(272	)
Investing Activities:
Investments, net		(166,866	)		36,629
Electric plant additions		(132,384	)		(167,442	)
Decommissioning fund deposits		(454	)		(511	)
Net Cash Used for Investing Activities		(299,704	)		(131,324	)
Net Change in Cash and Cash Equivalents		(37,738	)		(25,001	)
Cash and Cash Equivalents – Beginning of Period		67,829			77,981
Cash and Cash Equivalents – End of Period	$	30,091		$	52,980

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

1. In the opinion of our management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for a fair statement of our consolidated financial position as of September 30, 2003, and our consolidated results of operations, comprehensive income, and cash flows for the three and nine months ended September 30, 2003 and 2002. The consolidated results of operations for the three and nine months ended September 30, 2003, are not necessarily indicative of the results to be expected for the entire year. These financial statements should be read in conjunction with the financial statements and notes thereto included in our 2002 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

2. We adopted the Financial Accounting Standards Board Statement of Financial Accounting Standards (“SFAS”) No. 143 “Accounting for Asset Retirement Obligations” effective January 1, 2003. SFAS No. 143 requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized asset is depreciated over the useful life of the long-lived asset. SFAS No. 143 requires that any transition adjustment determined at adoption be recognized as a cumulative effect of change in accounting principle.

SFAS No. 143 applies to the decommissioning of the North Anna Nuclear Power Station (“North Anna”), certain asset retirement obligations at the Clover Power Station (“Clover”), as well as certain asset retirement obligations at the Rock Springs and Louisa combustion turbine facilities and our diesel facilities. At December 31, 2002, we had recorded a liability for the decommissioning of North Anna of $56.7 million, which equaled the balance in our nuclear decommissioning trust fund. At January 1, 2003, our liability for the decommissioning of North Anna as well as our liabilities associated with Clover and the diesel facilities as calculated under SFAS No. 143 were $39.0 million. This liability was calculated using the present value of estimated future cash flows. We also recorded plant assets totaling $12.3 million and offsetting accumulated depreciation of $4.4 million. The majority, $28.8 million, of the difference between what was recorded prior to January 1, 2003, and the net amount of what we recorded under SFAS No. 143 has been deferred as a regulatory liability. The remainder, $3.3 million, represents the cumulative effect of change in accounting principle.

In June 2003, our new Rock Springs and Louisa combustion turbine facilities began commercial operations and as a result we recorded $0.3 million in asset retirement obligations.

The following represents changes in our Asset Retirement Obligations for the nine months ended September 30, 2003:

	Nine Months Ended September 30, 2003
	(in thousands)
Decommissioning reserve	$	56,684
Cumulative effect of change in accounting principle		(17,641	)
Asset retirement obligations at January 1, 2003		39,043
Additional asset retirement obligations – new facilities		303
Accretion expense		1,557
Asset retirement obligations at September 30, 2003	$	40,903

Net margin for the three and nine months ended September 30, 2002, or the twelve months ended December 31, 2002, would not have differed if this statement had been adopted as of January 1, 2002.

3. In December 1992, we entered into an agreement with Public Service Electric & Gas Company (“PSE&G”) to purchase 150 megawatts (“MW”) of capacity, consisting of 75 MW of intermediate or peaking capacity and 75 MW of base load capacity, as well as reserves and associated energy, through 2004. The agreement with PSE&G contains fixed capacity charges, including transmission charges, for the base, intermediate, and peaking capacity to be provided under the agreement. However, either party can apply to the Federal Energy Regulatory Commission (“FERC”) in some circumstances to recover changes in specified costs of providing services. If a change in rate occurs, the party adversely affected may terminate the agreement on one year’s notice. We may purchase the energy associated with the PSE&G capacity from PSE&G or other power suppliers. If purchased from PSE&G, the energy cost is based on PSE&G’s incremental cost above its own power supply requirements.

6

In October 1997, we filed with FERC a complaint against PSE&G asserting that our agreement with PSE&G should be modified to conform to the restructuring of PJM Interconnection, LLC (“PJM”). Under the PJM structure, we pay for the transmission of PSE&G power through the zonal rate we currently pay Conectiv Energy. On May 14, 1998, FERC ruled in our favor as part of its ruling on several cases relating to the restructuring of PJM, ordering PSE&G to remove all transmission costs from its rates for capacity and associated energy sold to us, effective April 1, 1998. PSE&G complied with the FERC order by virtue of a compliance filing submitted to FERC on June 15, 1998. On November 30, 2000, PSE&G filed with the United States Court of Appeals for the District of Columbia Circuit a petition for review of FERC’s orders in this matter. On July 12, 2002, the Court of Appeals vacated FERC’s May 14, 1998 ruling and remanded all of these cases relating to the restructuring of PJM to FERC for further consideration.

On December 19, 2002, FERC issued an order on remand reversing its May 14, 1998 generic PJM restructuring ruling. FERC noted that there was no evidence on record in the generic restructuring proceeding to demonstrate what, if any, unduly discriminatory effects could be attributable to our particular contract, but went on to state that we are free to present evidence based on the specifics of our contract with PSE&G under Section 206 of the Federal Power Act. On January 24, 2003, we filed an amended and renewed complaint against PSE&G with FERC, requesting that FERC reopen the proceeding regarding the matters raised by our October 1997 complaint. That initial complaint was dismissed by FERC in August 1998, based on FERC’s generic PJM restructuring ruling that ruled in our favor. Our January 24, 2003, complaint renewal and amendment urges FERC to find that rate pancaking (incurring charges from multiple transmission owners due to transmission across several systems) to us under our agreement with PSE&G is unlawful and eliminate this rate pancaking treatment effective April 1, 1998, forward. We also requested that FERC stay any payment obligation by us to PSE&G for surcharge amounts of pancaked rates from April 1, 1998 through December 31, 2002. We received an invoice from PSE&G on January 22, 2003, for this surcharge amount of $26.2 million, plus $4.7 million in accumulated interest.

On February 10, 2003, we informed PSE&G in writing that a payment obligation for any past amount under the 1992 agreement’s surcharge authority remains unauthorized and premature, until so ordered by FERC. On January 14, 2003, our board of directors approved the collection from our member distribution cooperatives of approximately $32.9 million, which includes interest and related margin requirement, beginning February 1, 2003, over 48 months, to recover these amounts. We are paying the amount of pancaked rates on a prospective basis, subject to protest and FERC action on our renewed and amended complaint.

On October 22, 2003, FERC issued an order that denied our request to reopen the proceeding regarding the matters raised by our October 1997 complaint against PSE&G. We plan to file a request for re-hearing.

4. On May 9, 2001, we entered into a master power purchase and sales agreement with Enron Power Marketing, Inc. (“EPMI”). Pursuant to transactions we entered into under this agreement, EPMI was obligated to deliver power to us through December 31, 2003. Following its filing for bankruptcy protection on December 2, 2001, EPMI ceased scheduling deliveries of power under the agreement beginning December 15, 2001. We then terminated the agreement. In September 2003 we entered into a settlement with EPMI regarding amounts payable by us as a result of the termination. The settlement did not have a material impact on our financial position, results of operations, or cash flow due to the previous collection of the settlement amount through rates.

5. TEC Trading, Inc. (“TEC”) is owned by our member distribution cooperatives. TEC was formed 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 to supply our three combustion turbine facilities, and taking advantage of other power-related trading opportunities in the market, which will help lower our member distribution cooperatives’ costs. To fully participate in power and natural gas related markets, TEC must maintain credit support sufficient to meet delivery and payment obligations associated with power and natural gas trades. To assist TEC in providing this credit support, we have agreed to guarantee on an unsecured basis up to $42.5 million of TEC’s delivery and payment obligations associated with its power and natural gas trades. At September 30, 2003, we had guaranteed $10.0 million of obligations of TEC. During the three and nine months ended September 30, 2003, we had sales to TEC of $44.0 thousand and $14.1 million, respectively. During the three and nine months ended September 30, 2003, we had charged administrative services fees to TEC of $3,000 and $9,000, respectively.

6. In January 2003, the Financial Accounting Standards Board issued Interpretation No. 46, “Consolidation of Variable Interest Entities, an interpretation of Accounting Research Bulletin No. 51” (the “Interpretation”). The Interpretation requires the consolidation of entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. Currently, entities are generally consolidated by an enterprise when it has a controlling financial interest through ownership of a majority voting interest in the entity.

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For new entities created after February 1, 2003, the Interpretation is effective immediately; this new interpretation is effective for us by the end of 2004 for existing entities. We are continuing to evaluate the impact of applying this new statement.

7. In May 2003, the Financial Accounting Standards Board issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” SFAS No. 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. SFAS No. 150 requires that an issuer classify a financial instrument that is within the scope of SFAS No. 150 as a liability (or an asset in some circumstances), which previously may have been classified as equity.

We do not believe that this statement will have a material effect on the classification of Patronage Capital in our Consolidated Balance Sheet because any distributions of Patronage Capital are subject to the discretion of our board of directors and the restrictions contained in the Indenture of Mortgage and Deed of Trust, dated as of May 1, 1992, between Old Dominion and Crestar Bank (predecessor to Sun Trust Bank), as trustee, as supplemented and amended (the “Indenture”).

8. In July 2003, we issued $250.0 million of 2003 Series A Bonds under the Indenture. The bonds bear interest at 5.676% and mature in 2028. The majority of the proceeds will be used to fund construction costs associated with our combustion turbine facilities and to redeem some of our outstanding indebtedness in the future.

9. Certain reclassifications have been made to the prior year’s condensed consolidated financial statements to conform to the current year’s presentation.

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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, assumptions, and estimates, are not guarantees of future performance or the occurrence of any event 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, interest rates, future costs, 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 September 30, 2003, other than the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143,Accounting for Asset Retirement Obligations, there have been no significant changes with regard to our critical accounting policies as disclosed in our Annual Report on Form 10-K for the fiscal year ended December 31, 2002. The policies disclosed included the accounting for rate regulation and our margin stabilization plan.

On January 1, 2003, we adopted SFAS No. 143, which provides accounting requirements for the recognition and measurement of liabilities associated with the retirement of tangible long-lived assets. At September 30, 2003, our asset retirement obligations totaled $40.9 million, the majority of which relates to the decommissioning of our undivided ownership interest in the North Anna Nuclear Power Station (“North Anna”) and asset retirement obligations relating to the Clover Power Station (“Clover”), the Rock Springs and Louisa combustion turbine facilities and our diesel facilities.

Asset retirement obligations are recognized at fair value as incurred and capitalized as part of the cost of the related tangible long-lived assets. In the absence of quoted market prices, we base our estimates of the fair value of asset retirement obligations using present value techniques, involving discounted cash flow analysis. Measurement using these techniques is dependent upon many subjective factors, including the selection of discount and cost escalation rates, identification of planned retirement activities and related cost estimates and assertions of probability regarding the timing, nature and costs of these activities. We base inputs and assumptions on the best information available to us at the time the estimates are made. However, estimates of future cash flows relating to these asset retirement obligations are highly uncertain by nature and may vary significantly from actual results. For additional discussion of SFAS No. 143, see Footnote 2 in Notes to Condensed Consolidated Financial Statements.

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Results of Operations

Operating Revenues

Our operating revenues are derived from power sales to our members and non-members. Our sales to members include sales to our Class A members, which are our twelve member distribution cooperatives, and sales to our single Class B member, TEC Trading, Inc. (“TEC”). Our operating revenues by type of purchaser for the three and nine months ended September 30, 2003 and 2002, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
	(in thousands)				(in thousands)
Member revenues:
Member distribution cooperatives	$	133,712	$	127,073	$	388,694	$	370,857
TEC		44		291		14,101		699
Total member revenues		133,756		127,364		402,795		371,556
Non-member revenues		2,359		2,891		9,357		4,372
Total revenues	$	136,115	$	130,255	$	412,152	$	375,928

Our energy sales in megawatt hours (“MWh”) for our members and non-members were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
	(in MWh)				(in MWh)
Members energy sales:
Member distribution cooperatives		2,566,920		2,746,025		7,322,312		7,369,534
TEC		2,589		6,400		284,980		15,200
Total energy sales for members		2,569,509		2,752,425		7,607,292		7,384,734
Non-member energy sales		65,420		70,136		241,325		127,097
Total energy sales		2,634,929		2,822,561		7,848,617		7,511,831
Average costs to member distribution cooperatives (per MWh)	$	52.09	$	46.28	$	53.08	$	50.32

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 bill energy to each of our member and non-member customers based on the total MWh delivered to them each month and, with respect to our member distribution cooperatives, charge them an amount based on the base energy rate and fuel factor adjustment rate. Because energy cannot be stored, 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 is referred to as capacity. We use our generating facilities and rely on power purchase contracts to satisfy substantially all of our member distribution cooperatives’ capacity requirements. We bill capacity to each of our member distribution cooperatives monthly through our demand rate which is based on our budgeted capacity costs. The quantity billed to each member distribution cooperative is based on its requirement for energy during the hour of the month when the need for energy among all of the consumers in mainland Virginia or the Delmarva Peninsula, as applicable, is highest, measured in megawatts (“MW”).

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. Our formulary rate is based on our cost of service in meeting these requirements and consists of a demand rate, a base energy rate and a fuel factor adjustment rate. Our formulary rate also allows us to recover and refund amounts under our Margin Stabilization Plan and is intended to recover all our costs including our margin requirement. We adjust revenues and accounts payable-members or accounts receivable each quarter to reflect these amounts. See “Factors Affecting Results – Formulary Rate, and – Margin Stabilization Plan” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002, for a discussion of the Margin Stabilization Plan. Revenue from sales to TEC is made pursuant to our power sales contract with it.

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Our revenues from sales to our member distribution cooperatives by formulary rate component for the three and nine months ended September 30, 2003 and 2002, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2003		2002		2003		2002
	(in thousands)				(in thousands)
Base energy revenues	$	46,450	$	49,536	$	132,685	$	133,069
Fuel factor adjustment revenues		31,889		26,494		80,372		81,837
Total energy revenues		78,339		76,030		213,057		214,906
Demand (capacity) revenues		55,373		51,043		175,637		155,951
Total revenues from sales to member distribution cooperatives	$	133,712	$	127,073	$	388,694	$	370,857

Three factors significantly affect our member distribution cooperatives’ consumers’ requirements for power:

• growth in the number of consumers,

• growth in consumers’ requirements for power, and

• weather fluctuations.

Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning or heating systems, respectively. Mild weather generally reduces the demand for energy because air conditioning and heating systems are operated less. Other factors affecting our member distribution cooperatives’ consumers’ demand for energy include the amount, size, and usage of electronics and machinery, and the expansion of operations among their commercial and industrial customers.

Total revenues from our member distribution cooperatives for the three months ended September 30, 2003, increased $6.6 million, or 5.2%, over the same period in 2002 as a result of two increases in our rates earlier in 2003 in response to actual and projected increases in capacity and energy costs for the period. These increases in costs, combined with lower sales volumes, caused our average capacity and energy costs for the quarter to be approximately 13.5% and 9.8% higher than for the same period in 2002, respectively. In the third quarter of 2003, capacity sales, measured in MW, decreased 4.4% and energy sales, measured in MWh, decreased 7.0% over those realized in the third quarter of 2002. Sales volumes decreased primarily as a result of milder weather conditions experienced by consumers of our member distribution cooperatives, which reduced the operating of home cooling systems.

Effective February 1, 2003, we increased the demand component of our formulary rate (which collects our capacity-related costs) approximately 5.0% to collect from our member distribution cooperatives transmission charges associated with our power purchase agreement with Public Service Electric & Gas Company (“PSE&G”). We anticipate that the increase in the demand component of our formulary rate will recover over 48 months $32.9 million related to a surcharge billed to us by PSE&G, and associated interest expense and margin requirement. Additionally, we anticipate that the revised demand component of our formulary rate will recover the amount of transmission costs that we are paying to PSE&G now until the termination of the contract in December 2004. We are making these payments under protest and subject to FERC action on this issue. See “Legal Proceedings” in Part II, Item 1.

Effective March 31, 2003, we increased our fuel factor adjustment rate, which resulted in an increase to our total energy rate (including our base energy rate and our fuel factor adjustment rate) of approximately 21.8%. The increase in the fuel factor adjustment rate was necessary to recover higher than expected actual energy costs that we incurred in the first two months of 2003 and energy costs for the remainder of the year that we anticipate will be higher than the energy costs we originally budgeted for 2003. The previous change to our fuel factor adjustment rate was effective October 1, 2002, when we reduced our total energy rate approximately 9.5% because we had over-collected our energy costs incurred to date and anticipated that the lower rate would adequately recover our energy costs in the future. See “Operating Expenses” below for a discussion of factors impacting both capacity and energy costs.

Total revenues from our member distribution cooperatives for the nine months ended September 30, 2003, increased $17.8 million, or 4.8%, over the same period in 2002 primarily as a result of a 13.9% increase in the average capacity costs for the period. Our revenues from our member distribution cooperatives for the nine months ended September 30, 2003, and accounts payable-members at September 30, 2003, reflect a $1.2 million margin stabilization. See “Factors Affecting Results – Margin Stabilization Plan” in Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002. For the

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nine months ended September 30, 2003, there was no material change in the volume of energy or capacity sales. Colder than normal weather experienced during the first quarter of 2003 yielded an increase in sales volumes as compared with the first quarter of 2002; however, milder weather during the second and third quarters of 2003 tempered these increases.

Sales to TEC.Our sales to TEC are primarily sales of energy that we do not need to meet the actual needs of our member distribution cooperatives. (We refer to this energy as excess energy.) These sales decreased $0.2 million and increased $13.4 million for the three and nine months ended September 30, 2003, respectively, as compared to the same periods in 2002. No sales were made to TEC during the first quarter of 2002.

Sales to Non-Members.Sales to non-members consist of sales of excess purchased energy and sales of excess generated energy from Clover. We sell excess purchased energy to PJM Interconnection, LLC (“PJM”) under its rates for providing energy imbalance services or to TEC. We sell excess energy from Clover to Virginia Power pursuant to the requirements of the Clover Operating Agreement. Non-member revenues for the three months ended September 30, 2003, were lower than in 2002 by $0.5 million. Non-member revenues for the nine months ended September 30, 2003, were $5.0 million higher than the same period in 2002 primarily because of sales to PJM of excess energy purchased under the option contract discussed in “Sales to TEC” above.

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 North Anna, our Rock Springs and Louisa combustion turbine facilities, and ten diesel generators, and (ii) power purchases from third parties through power purchase contracts and forward, short-term and spot market energy purchases. Rock Springs’ two units began commercial operations in June 2003 and Louisa’s five units began commercial operations in June and July of 2003. Our energy supply for the three and nine months ended September 30, 2003 and 2002, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in MWh or percentages)						(in MWh or percentages)
Generated:
Clover	884,086	32.9	%	913,332	31.6	%	2,294,949	28.5	%	2,223,757	29.0	%
North Anna	471,635	17.5		411,354	14.2		1,123,459	13.9		1,346,681	17.5
Louisa	91,524	3.4		—	—		120,245	1.5		—	—
Rock Springs	93,807	3.5		—	—		109,648	1.4		—	—
Diesels	283	—		528	—		594	—		528	—
Total Generated	1,541,335	57.3		1,325,214	45.8		3,648,895	45.3		3,570,966	46.5
Purchased:
Mainland Virginia area	603,817	22.5		873,038	30.2		2,344,210	29.1		2,409,418	31.3
Delmarva Peninsula area	542,375	20.2		694,060	24.0		2,061,898	25.6		1,702,676	22.2
Total Purchased	1,146,192	42.7		1,567,098	54.2		4,406,108	54.7		4,112,094	53.5
Total Available Energy	2,687,527	100.0	%	2,892,312	100.0	%	8,055,003	100.0	%	7,683,060	100.0	%

Market forces influence the structure of new power supply contracts into which we enter. To serve the Delmarva Peninsula, we rely on Rock Springs and power purchase agreements to provide the capacity to meet our member distribution cooperatives’ capacity requirements. To meet our member distribution cooperatives’ energy requirements on the Delmarva Peninsula, we purchase energy from the market, or when economical, we utilize the PJM power pool or generate power from Rock Springs. In mainland Virginia, we satisfy the majority of our member distribution cooperatives’ capacity and energy requirements through our ownership interests in Clover, North Anna and Louisa and we purchase energy from the market when economical.

Base load generating facilities, particularly nuclear power plants such as North Anna, generally have relatively high fixed costs. Nuclear facilities operate with relatively low variable costs due to lower fuel costs and technological efficiencies. In addition, coal-fired facilities have relatively low variable costs compared to combustion turbine facilities such as Rock Springs and Louisa. Owners of nuclear and other power plants incur the embedded fixed costs of these facilities whether or not the units operate. When either North Anna or Clover is off-line, we must purchase replacement energy from either Virginia Power, which is more costly, or the market, which may be more or less costly. As a result, our operating expenses, and consequently our rates to our member distribution

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cooperatives, are significantly affected by the operations of North Anna and Clover but not Rock Springs or Louisa. Our combustion turbine facilities have relatively low fixed costs and greater operational flexibility, but are more expensive to operate and, as a result, we will operate them only when the market price of energy makes their operation economical. The output of North Anna and Clover for the three and nine months ended September 30, 2003, and 2002, as a percentage of the maximum dependable capacity rating of the facilities was as follows:

	North Anna				Clover
	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended September 30,		Nine Months Ended September 30,
	2003	2002	2003	2002	2003	2002	2003	2002
Unit 1	100.2%	99.7%	73.6%	100.7%	92.4%	93.0%	83.4%	69.2%
Unit 2	99.7	74.6	87.0	91.7	91.1	94.6	76.7	86.2
Combined	100.0	87.2	80.3	96.2	91.8	93.8	80.1	77.7

North Anna.North Anna Unit 1 began an outage for a scheduled refueling and to replace the reactor vessel head of the unit on February 23, 2003. The unit was returned to service on April 18, 2003. During the first nine months of 2003, North Anna Unit 1 experienced a non-nuclear unscheduled ten-day outage. There were no maintenance outages at North Anna Unit 1 during the first nine months of 2002. North Anna Unit 2 began a scheduled refueling outage on September 8, 2002 after being online since December of 2001. After the outage began, the reactor vessel head was replaced and the unit and was returned to service on February 2, 2003. See also Part II, Item 7 of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002, for a discussion of the replacement of the reactor vessel heads at North Anna.

Clover.Clover Unit 1 began a scheduled maintenance outage on April 11, 2003, and was returned to service on May 1, 2003. Clover Unit 2 was removed from service on March 14, 2003, for a scheduled maintenance outage and was returned to service on April 19, 2003. Clover Unit 1 was removed from service for a scheduled maintenance outage on March 1, 2002, and was returned to service on April 20, 2002. Clover Unit 2 was removed from service on April 20, 2002, for a scheduled maintenance outage and was returned to service on May 3, 2002. Both Unit 1 and Unit 2 also experienced minor scheduled and unscheduled outages during the first nine months of 2003 and 2002.

The components of our operating expenses for the three and nine months ended September 30, 2003 and 2002, were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2003		2002			2003			2002
	(in thousands)					(in thousands)
Fuel	$	27,318	$	16,024		$	56,473		$	41,889
Purchased power		59,819		95,741			243,064			222,495
Deferred energy		5,766		(10,009	)		(3,822	)		23,290
Operations and maintenance		7,608		8,785			33,040			25,682
Administrative and general		6,946		5,928			18,813			16,660
Depreciation, amortization and decommissioning		8,304		5,986			19,129			17,687
Amortization of regulatory asset/(liability), net		1,733		(3,801	)		(844	)		(7,603	)
Taxes, other than income taxes		1,057		854			2,720			2,561
Accretion		511		—			1,557			—
Total Operating Expenses	$	119,062	$	119,508		$	370,130		$	342,661

Aggregate operating expenses for the three months ended September 30, 2003 remained relatively flat as compared to the same period in 2002 primarily because of a decrease in purchased power expense effectively offset by an increase in fuel expense and deferred energy expense, and a change in the amortization of regulatory asset/(liability), net. Purchased power expense decreased $35.9 million, or 37.5%, because we generated more power in the third quarter of 2003 as compared to the third quarter of 2002, resulting in lower purchased power costs. Additionally, the average cost of the power we purchased decreased 14.6% in the third quarter of 2003 as compared to the third quarter of 2002. Purchased power expense for the third quarter of 2003 included $1.4 million associated with the current portion of disputed charges under the PSE&G contract. There were no amounts included in the third quarter of 2002 for the disputed charges under the PSE&G contract.

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Fuel expense incurred to operate our generating units increased $11.3 million, or 70.5%, in the third quarter of 2003 as compared with the third quarter of 2002, due to the purchase of natural gas and fuel oil for the operation of our Louisa and Rock Springs combustion turbine facilities. Deferred energy expense increased $15.8 million, or 157.6%, for the third quarter of 2003 as compared with the third quarter of 2002. During the third quarter of 2003 we collected $5.8 million in energy costs in excess of the energy costs incurred during the quarter. During the third quarter of 2002, our energy cost exceeded the amount we collected through our total energy rate by $10.0 million. The expense incurred through amortization of regulatory asset/(liability), net increased $5.5 million, or 145.6%, for the third quarter of 2003 as compared with the third quarter of 2002. During the third quarter of 2003, we recorded expense of $1.7 million relating primarily to the amortization of the regulatory asset associated with the PSE&G contract. During the third quarter of 2002, we recorded a negative charge of $3.8 million as amortization of regulatory asset/liability, net related to the amortization of deferred revenue from 2001.

Aggregate operating expenses for the nine months ended September 30, 2003, increased $27.5 million, or 8.0%, over the same period in 2002 primarily because of increases in purchased power expense, fuel expense, operations and maintenance expense, and a change in amortization of regulatory asset/(liability), net partially offset by a decrease in deferred energy expense. Purchased power expense increased $20.6 million, or 9.2%. During the first quarter of 2003 we purchased additional energy from the market to supply our member distribution cooperatives’ requirements during unusually cold winter weather and to replace energy normally provided by, but not available from, North Anna due to the replacement of the reactor vessel heads. Additionally, we exercised a contractual option to purchase energy at then favorable market prices for the use of our member distribution cooperatives, and sold the energy that was not utilized by them to TEC or non-members. The average cost of the power we purchased increased 2.0% for the first nine months of 2003 as compared to the same period of 2002. Purchased power expense for the first nine months of 2003 included $3.7 million associated with the current portion of disputed charges under the PSE&G contract. There were no amounts included in the first nine months of 2002 for disputed charges under the PSE&G contract.

Fuel expense incurred to operate our generating units increased $14.6 million, or 34.8%, for the nine months ended September 30, 2003, as compared to the same period in 2002, because of an increase in fuel purchases to operate our Louisa and Rock Springs combustion turbine facilities. Operations and maintenance expense increased $7.4 million, or 28.7%, for the first nine months of 2003 as compared to the same period in 2002, primarily due to costs incurred for the replacement of the reactor vessel heads at North Anna. Amortization of regulatory asset/liability, net increased $6.8 million, or 88.9%, for the nine months ended September 30, 2003, as compared to the same period in 2002. During the first nine months of 2003, we recorded a $5.3 million charge associated with the collection of disputed charges under the PSE&G contract. This was offset by the recognition of $5.6 million in negative charges related to the amortization of deferred revenue from 2002 for the North Anna reactor vessel head replacement. During the first nine months of 2002, we recorded a negative charge of $7.6 million as amortization of regulatory asset/liability, net related to the amortization of deferred revenue from 2001.

Deferred energy expense decreased $27.1 million, or 116.4%, for the first nine months of 2003 as compared with the same period of 2002. For the first nine months of 2003, our incurred energy cost exceeded the amount we collected through our total energy rate by $3.8 million. At September 30, 2003, we had an under-collected deferred energy balance of $0.8 million, which we anticipate will be fully collected through rates by the end of 2003. During the first nine months of 2002, we collected $23.3 million in energy costs in excess of the energy costs incurred during that period.

Other Items

Other Income/(Expense, net. The major components of our other income/(expense), net for the three and nine months ended September 30, 2003 and 2002, were as follows:

	Three Months Ended September 30,					Nine Months Ended September 30,
	2003		2002			2003			2002
	(in thousands)					(in thousands)
Gain on sale of investments	$	—	$	—		$	—		$	90
Reimbursement of prior costs		—		—			—			740
Other		172		(17	)		(82	)		(116	)
Total Other Income/(Expense), net	$	172	$	(17	)	$	(82	)	$	714

Other income/(expense), net increased in the third quarter of 2003 by $0.2 million as compared to the same period in 2002 primarily due to fees received for load management.

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Other income/(expense), net increased in the first nine months of 2003 by $0.8 million as compared to the same period in 2002 due to this donation of transmission assets offset by the reimbursement by the other participant in the Rock Springs facility in 2002 of previously incurred development costs.

Investment Income.Investment income remained relatively flat in the third quarter of 2003 as compared to the same period in 2002.

Investment income decreased in the first nine months of 2003 by $0.5 million, or 21.4% as compared to the same period in 2002 primarily because of a reduction of investment income from investments-other, and cash and cash equivalents partially offset by investment income from our nuclear decommissioning trust. The average balance in investments-other and cash and cash equivalents was lower in 2003 than 2002 due to the funding of the development and construction of our three combustion turbine facilities

Interest Charges, net. The primary factors affecting our interest expense are scheduled payments of principal on our indebtedness, prepayments of indebtedness relating to the Strategic Plan Initiative, issuance of new indebtedness, and capitalized interest.

The major components of interest charges, net for the three and nine months ended September 30, 2003 and 2002, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2003			2002			2003			2002
	(in thousands)						(in thousands)
Interest expense on long-term debt	$	(15,508	)	$	(12,540	)	$	(41,364	)	$	(37,643	)
Other		(827	)		(66	)		(2,393	)		(174	)
Total Interest Charges		(16,335	)		(12,606	)		(43,757	)		(37,817	)
Allowance for borrowed funds used during construction		1,925			3,936			11,902			8,932
Interest Charges, net	$	(14,410	)	$	(8,670	)	$	(31,855	)	$	(28,885	)

Interest charges, net increased in the third quarter of 2003 by $5.7 million or 66.2% as compared to the third quarter of 2002 primarily due to increased interest expense related to the issuance of the $250.0 million 2003 Series A Bonds issued in July 2003 and by a decrease in the amount of capitalized interest relating to the development and construction of our three combustion turbine facilities. We began capitalizing interest on the Rock Springs and Louisa facilities in October 2001 and January 2002, respectively. We ceased capitalizing interest for our Rock Springs and Louisa facilities when the facilities began commercial operations in June. Capitalized interest is computed monthly using an interest rate, which reflects our embedded cost of indebtedness, multiplied by our investment in projects under construction. Other interest increased in both the quarter and year-to-date due to an amount in dispute with PSE&G. See “Legal Proceedings” in Part II, Item 1.

Interest charges, net increased in the first nine months of 2003 by $3.0 million, or 10.3%, over the same period in 2002 primarily due to an increase in interest expense on long-term debt due to the issuance of the 2003 Series A Bonds, offset by an increase in capitalized interest relating to the development and construction of our three combustion turbine facilities.

Net Margin. Our net margin, which is a function of our interest charges, increased $0.7 million, or 29.6%, and $1.2 million, or 15.7%, in the third quarter and first nine months of 2003, respectively, as compared to the same periods in 2002, due to the $3.7 million and $5.9 million increase in our total interest charges for the third quarter and first nine months of 2003, respectively.

Financial Condition

The principal changes in our financial condition from December 31, 2002 to September 30, 2003, were caused by increases in electric plant in service partially offset by the decrease in construction work in progress, an increase in investments-other and long-term debt and adjustments related to the adoption of SFAS No. 143. The increase in electric plant in service and the corresponding decrease in construction work in progress is primarily due to our Louisa and Rock Springs combustion turbine facilities being placed in service in June of 2003. The increase in investments-other of $166.9 million, or 214.1%, and the increase in long-term debt of $252.0 million, or 33.6%, are primarily a result of the issuance of the 2003 Series A Bonds.

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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 generating facilities, our debt service requirements, and our ordinary business operations. Our operating activities provided cash flows of $12.2 million and $106.6 million during the first nine months of 2003 and 2002, respectively. Operating activities for the first nine months of 2003 were affected primarily by changes between periods in our current assets, deferred energy, current liabilities and regulatory assets and liabilities.

Financing Activities.In addition to liquidity from our operating activities, we maintain committed lines of credit to cover short-term funding needs. Currently, we have short-term committed variable rate lines of credit in an aggregate amount of $245.0 million. Of this amount, $125.0 million is available for general working capital purposes and $120.0 million is available for capital expenditures related to our generating facilities, including the development and construction of our three combustion turbine facilities.

At September 30, 2003 and 2002, 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 lines of credit to be renewed until no longer necessary for the development and construction of our combustion turbine facilities.

To fully participate in power-related markets, TEC must maintain credit support sufficient to meet delivery and payment obligations associated with power and natural gas trades. To assist TEC in providing this support, we have agreed to guarantee on an unsecured basis up to $42.5 million of TEC’s delivery and payment obligations associated with its power trades. At September 30, 2003, we had guaranteed $10.0 million of obligations of TEC.

In July 2003, we issued $250.0 million of 2003 Series A Bonds under our Indenture. The bonds bear interest at 5.676% and mature in 2028. The majority of the proceeds will be used to fund construction costs associated with our combustion turbine facilities and to redeem some of our outstanding indebtedness in the future.

Investing Activities.Investing activities in the first nine months of 2003 consisted primarily of expenditures for our three combustion turbine facilities and liquidating investments-other to fund construction and development expenses.

Competition and Changing Regulations

All of the customers of Delaware Electric Cooperative and Choptank Electric Cooperative (our Delaware and Maryland member distribution cooperatives, respectively), as well as all of the customers of four Virginia member distribution cooperatives (Community Electric Cooperative, Northern Virginia Electric Cooperative, Rappahannock Electric Cooperative, and Shenandoah Valley Electric Cooperative), were free to choose an alternative power supplier as of September 30, 2003. Additionally, as of October 1, 2003, the customers of our Southside Electric Cooperative in Virginia are now free to choose an alternative power supplier. These seven member distribution cooperatives accounted for 86.3% of our capacity requirements in 2002. As of November 11, 2003, none of the customers of these member distribution cooperatives had chosen an alternative power supplier and no alternative power suppliers were registered to provide power to customers of our member distribution cooperatives.

Recent Developments

As part of our regular evaluation of our power supply and resource options, on May 9, 2003, we issued a request for proposals to serve specified portions of our member distribution cooperatives’ capacity or energy requirements on the Delmarva Peninsula. Based upon responses to our request, we have entered into several agreements for energy supplies in 2004 and 2005.

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OLD DOMINION ELECTRIC COOPERATIVE

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

We began commercial operation of our Louisa and Rock Springs combustion turbine facilities in June 2003. These facilities are fueled by natural gas and as such we are exposed to market price risk for purchases of natural gas. For a discussion of how we manage fuel price risk and other market risk see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk – Market Price Risk” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2002.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures

Our management, including the President and Chief Executive Officer, and Senior Vice President Accounting and Finance, the Chief Financial Officer, conducted an evaluation of the effectiveness of our disclosure controls and procedures as defined in Rules 13a-15(e) or 15d-15(e) under the Securities Exchange Act of 1934 within 90 days of this report. Based upon that evaluation, the President and Chief Executive Officer, and Senior Vice President Accounting and Finance, the 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. Due to some inherent limitations of the effectiveness of any established controls or procedures, our management cannot provide absolute assurance that the objectives of their disclosure and controls procedures will be met.

Changes in Internal Controls

There has been no change in any of our internal control over financial reporting that occurred during our most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

On October 22, 2003, FERC issued an order that denied our request to reopen the proceeding regarding the matters raised by our October 1997 complaint against PSE&G. We plan to file a request for re-hearing.

In September 2003, we entered into a settlement with Enron Power Marketing, Inc. regarding amounts payable by us as a result of the termination of our agreement. The settlement did not have a material impact on our financial position, results of operations, or cash flow due to our ability to collect such amount through rates.

Other than certain 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.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits

31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)	21
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)	22
32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350	23
32.2	Certification of the Principal Financial Officer pursuant to 18 U.S.C. § 1350	24

(b) Reports on Form 8-K.

The Registrant filed the following reports on Form 8-K during the quarter ended September 30, 2003:

Date of Report	Date Filed	Item(s) Reported
July 23, 2003	July 25, 2003	7
July 17, 2003	July 17, 2003	5,7

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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.

	OLD DOMINION ELECTRIC COOPERATIVE
	Registrant
Date: November 12, 2003	/s/    Daniel M. Walker
	Daniel M. Walker
	Senior Vice President Accounting and Finance
	(Chief Financial Officer)

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EXHIBIT INDEX

Exhibit Number	Description of Exhibit	Page Number
31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a)	21
31.2	Certification of the Principal Financial Officer pursuant to Rule 13a-14(a)	22
32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350	23
32.2	Certification of the Principal Financial Officer pursuant to 18 U.S.C. § 1350	24

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