10-Q

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)


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

For the quarterly period ended September 30, 2024


☐	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)

Securities registered pursuant to Section 12(b) of the Act: NONE

Securities registered pursuant to Section 12(g) of the Act: NONE

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act: NONE

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

GLOSSARY OF TERMS

The following abbreviations or acronyms used in this Form 10-Q are defined below:


Abbreviation or Acronym		Definition

ACES		Alliance for Cooperative Energy Services Power Marketing, LLC

Clover		Clover Power Station

EPA		Environmental Protection Agency

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States

Louisa		Louisa Power Station

Marsh Run		Marsh Run Power Station

MMBTU		One million British Thermal Units

Moody's		Moody's Investors Service

MWh		Megawatt hour(s)

North Anna		North Anna Nuclear Power Station

NYMEX		New York Mercantile Exchange

ODEC, We, Our, Us		Old Dominion Electric Cooperative

PJM		PJM Interconnection, LLC

S&P		Standard & Poor's Financial Services LLC

TEC		TEC Trading, Inc.

Wildcat Point		Wildcat Point Generation Facility

XBRL		Extensible Business Reporting Language

OLD DOMINION ELECTRIC COOPERATIVE

INDEX


		Page Number

PART I. Financial Information

Item 1. Financial Statements

Condensed Consolidated Balance Sheets – September 30, 2024 (unaudited) and December 31, 2023		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three and Nine Months Ended September 30, 2024 and 2023		5

Condensed Consolidated Statements of Cash Flows (unaudited) – Nine Months Ended September 30, 2024 and 2023		6

Notes to Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		13

Item 3. Quantitative and Qualitative Disclosures About Market Risk		22

Item 4. Controls and Procedures		23

PART II. Other Information		24

Item 1. Legal Proceedings		24

Item 1A. Risk Factors		24

Item 5. Other Information		24

Item 6. Exhibits		25

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2024			December 31, 2023
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,579,018		$	2,566,211
Less accumulated depreciation		(1,212,348	)		(1,173,293	)
Net Property, plant, and equipment		1,366,670			1,392,918
Nuclear fuel, at amortized cost		16,457			16,340
Construction work in progress		80,046			80,088
Net Electric Plant		1,463,173			1,489,346
Investments:
Nuclear decommissioning trust		296,992			260,607
Unrestricted investments and other		2,283			2,314
Total Investments		299,275			262,921
Current Assets:
Cash and cash equivalents		88,105			31,284
Accounts receivable		3,829			3,371
Accounts receivable–members		102,222			108,160
Fuel, materials, and supplies		130,396			135,445
Prepayments and other		19,621			22,714
Total Current Assets		344,173			300,974
Deferred Charges and Other Assets:
Regulatory assets		68,324			94,274
Other assets		73,032			84,835
Total Deferred Charges and Other Assets		141,356			179,109
Total Assets	$	2,247,977		$	2,232,350
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	497,643		$	488,635
Non-controlling interest		6,730			6,586
Total Patronage capital and Non-controlling interest		504,373			495,221
Long-term debt		923,838			923,545
Revolving credit facility		55,000			191,000
Total Long-term debt and Revolving credit facility		978,838			1,114,545
Total Capitalization		1,483,211			1,609,766
Current Liabilities:
Long-term debt due within one year		49,041			49,041
Accounts payable		65,365			75,106
Accounts payable–members		119,816			44,540
Accrued expenses		20,224			6,321
Deferred energy		78,187			30,702
Total Current Liabilities		332,633			205,710
Deferred Credits and Other Liabilities:
Asset retirement obligations		201,463			196,747
Regulatory liabilities		173,556			142,101
Other liabilities		57,114			78,026
Total Deferred Credits and Other Liabilities		432,133			416,874
Total Capitalization and Liabilities	$	2,247,977		$	2,232,350

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
	(in thousands)
Operating Revenues	$	305,779		$	294,561		$	839,874		$	824,614
Operating Expenses:
Fuel		52,096			47,502			151,705			148,335
Purchased power		107,270			89,222			272,528			246,492
Transmission		51,058			44,442			150,110			129,030
Deferred energy		24,122			38,865			47,485			86,557
Operations and maintenance		22,475			25,709			69,770			67,196
Administrative and general		12,536			10,879			37,108			32,121
Depreciation and amortization		17,600			17,439			52,616			52,104
Amortization of regulatory asset/(liability), net		920			634			12,475			1,121
Accretion of asset retirement obligations		1,573			1,520			4,716			4,557
Taxes, other than income taxes		2,323			2,244			6,944			6,837
Total Operating Expenses		291,973			278,456			805,457			774,350
Operating Margin		13,806			16,105			34,417			50,264
Other income (expense), net		9			7			8			(200	)
Investment income		2,799			2,530			18,112			6,437
Interest charges, net		(13,692	)		(15,426	)		(43,335	)		(46,634	)
Income taxes		(17	)		(15	)		(50	)		(94	)
Net Margin including Non-controlling interest		2,905			3,201			9,152			9,773
Non-controlling interest		(49	)		(45	)		(144	)		(242	)
Net Margin attributable to ODEC		2,856			3,156			9,008			9,531
Patronage Capital - Beginning of Period		494,787			482,457			488,635			476,082
Patronage Capital - End of Period	$	497,643		$	485,613		$	497,643		$	485,613

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Nine Months Ended September 30,
	2024			2023
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	9,152		$	9,773
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		52,616			52,104
Other non-cash charges		13,010			12,750
Change in current assets		13,622			4,776
Change in deferred energy		47,485			86,557
Change in current liabilities		85,995			(79,003	)
Change in regulatory assets and liabilities		36,578			(61,337	)
Change in deferred charges and other assets and deferred credits and other liabilities		(9,121	)		36,192
Net Cash Provided by Operating Activities		249,337			61,812
Investing Activities:
Purchases of available for sale securities		(15,000	)		—
Proceeds from sale of available for sale securities		15,000			—
Increase in other investments		(15,515	)		(4,167	)
Electric plant additions		(41,001	)		(35,683	)
Net Cash Used for Investing Activities		(56,516	)		(39,850	)
Financing Activities:
Draws on revolving credit facility		151,000			318,000
Repayments on revolving credit facility		(287,000	)		(278,000	)
Net Cash (Used for) Provided by Financing Activities		(136,000	)		40,000
Net Change in Cash and Cash Equivalents		56,821			61,962
Cash and Cash Equivalents - Beginning of Period		31,284			15,213
Cash and Cash Equivalents - End of Period	$	88,105		$	77,175

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

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

General

The accompanying unaudited condensed consolidated financial statements, which represent the consolidated financial statements of ODEC and TEC, have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of 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, 2024, our consolidated results of operations for the three and nine months ended September 30, 2024 and 2023, and cash flows for the nine months ended September 30, 2024 and 2023. The consolidated results of operations for the three and nine months ended September 30, 2024, 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 2023 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

We have two classes of members. Our eleven Class A members are customer-owned electric distribution cooperatives engaged in the retail sale of power to member customers located in Virginia, Delaware, and Maryland. Our sole Class B member is TEC, a taxable corporation owned by our member distribution cooperatives. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. In accordance with Consolidation Accounting, TEC is considered a variable interest entity for which we are the primary beneficiary. We have eliminated all intercompany balances and transactions in consolidation. The assets and liabilities and non-controlling interest of TEC are recorded at carrying value and the consolidated assets were $6.7 million and $6.6 million as of September 30, 2024 and December 31, 2023, respectively. TEC's assets are utilized to settle TEC's liabilities. The income taxes reported on our Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC. As TEC is wholly-owned by our Class A members, its equity is presented as a non-controlling interest in our consolidated financial statements.

Our rates are set periodically by a formula that was accepted for filing by FERC and are not regulated by the public service commissions of the states in which our member distribution cooperatives operate.

We comply with the Uniform System of Accounts as prescribed by FERC. In conformity with 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 condensed 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. We did not have any other comprehensive income for the periods presented.

Fair Value Measurements

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

The following tables summarize our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2024 and December 31, 2023:


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	September 30,		Assets		Inputs		Inputs
	2024		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	97,510	$	97,510	$	—	$	—
Nuclear decommissioning trust - net asset value (1)(2)		199,482		—		—		—
Unrestricted investments and other (3)		106		—		106		—
Derivatives - gas and power (4)		3,035		—		1,257		1,778
Total financial assets	$	300,133	$	97,510	$	1,363	$	1,778

Derivatives - gas and power (4)	$	56,120	$	53,591	$	2,529	$	—
Total financial liabilities	$	56,120	$	53,591	$	2,529	$	—


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs
	2023		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	78,243	$	78,243	$	—	$	—
Nuclear decommissioning trust - net asset value (1)(2)		182,364		—		—		—
Unrestricted investments and other (3)		137		—		137		—
Derivatives - gas and power (4)		441		—		441		—
Total financial assets	$	261,185	$	78,243	$	578	$	—

Derivatives - gas and power (4)	$	77,001	$	65,285	$	10,715	$	1,001
Total financial liabilities	$	77,001	$	65,285	$	10,715	$	1,001

(1)

For additional information about our nuclear decommissioning trust, see Note 4—Investments below.

(2)

Nuclear decommissioning trust includes investments measured at net asset value per share (or its equivalent) as a practical expedient and these investments have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our Condensed Consolidated Balance Sheet.

(3)

Unrestricted investments and other includes investments that are related to equity securities.

(4)

Derivatives - gas and power represent natural gas futures contracts (Level 1 and Level 2) and financial transmission rights (Level 3). Level 1 are indexed against NYMEX. Level 2 are valued by ACES using observable market inputs for similar transactions. Level 3 are valued by ACES using unobservable market inputs, including situations where there is little market activity. Sensitivity in the market price of financial transmission rights could impact the fair value. For additional information about our derivative financial instruments, see Note 1 of the Notes to Consolidated Financial Statements in our 2023 Annual Report on Form 10-K.

Derivatives and Hedging

We are exposed to market price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation. In addition, the purchase of fuel to operate our generating facilities

also exposes us to market price risk. To manage this exposure, we utilize derivative instruments. See Note 1 of the Notes to Consolidated Financial Statements in our 2023 Annual Report on Form 10-K.

Changes in the fair value of our derivative instruments accounted for at fair value are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating activities section of our Condensed Consolidated Statements of Cash Flows.

Outstanding derivative instruments, excluding contracts accounted for as normal purchase/normal sale, were as follows:



		Quantity
		As of September 30,		As of December 31,
Commodity	Unit of Measure	2024		2023
Natural gas	MMBTU		123,630,000		111,070,000
Purchased power - financial transmission rights	MWh		8,625,308		9,382,175

The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows:


		Fair Value
		As of September 30,		As of December 31,
	Balance Sheet Location	2024		2023
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	1,257	$	441
Financial transmission rights	Other assets		1,778		—
Total Derivatives in an asset position		$	3,035	$	441

Derivatives in a liability position:
Natural gas futures contracts	Other liabilities	$	56,120	$	76,000
Financial transmission rights	Other liabilities		—		1,001
Total Derivatives in a liability position		$	56,120	$	77,001

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three and Nine Months Ended September 30, 2024 and 2023


	Amount of Gain						Location of	Amount of Gain (Loss) Reclassified from
	(Loss) Recognized						Gain (Loss)	Regulatory Asset/Liability
	in Regulatory						Reclassified	into Income for the
Derivatives	Asset/Liability for						from Regulatory	Three Months						Nine Months
Accounted for Utilizing	Derivatives as of						Asset/Liability	Ended						Ended
Regulatory Accounting	September 30,						into Income	September 30,						September 30,
	2024			2023				2024			2023			2024			2023
	(in thousands)							(in thousands)
Natural gas futures contracts	$	(57,853	)	$	(29,360	)	Fuel	$	(15,245	)	$	(14,351	)	$	(49,580	)	$	(56,488	)
Purchased power		1,778			(4,674	)	Purchased power		8,176			5,188			(3,859	)		(12,287	)
Total	$	(56,075	)	$	(34,034	)		$	(7,069	)	$	(9,163	)	$	(53,439	)	$	(68,775	)

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to mitigate our power market price risks. Because we rely substantially on the use of hedging instruments, we are exposed to the risk that counterparties will default in performance of their obligations to us. Although we assess the creditworthiness of counterparties and other credit issues related to these hedging instruments, and we may require our counterparties to post collateral with us, defaults may still occur. Defaults may take the form of failure to physically deliver purchased energy or failure to pay. If a default occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term, or spot markets at then-current market prices that may exceed the prices previously agreed upon with the defaulting counterparty.

Investments

Investments were as follows as of September 30, 2024 and December 31, 2023:


			Gross		Gross
			Unrealized		Unrealized			Fair		Carrying
Description	Cost		Gains		Losses			Value		Value
	(in thousands)
September 30, 2024
Nuclear decommissioning trust (1)
Debt securities	$	107,436	$	—	$	(10,038	)	$	97,398	$	97,398
Equity securities		94,935		107,677		(3,130	)		199,482		199,482
Cash and other		112		—		—			112		112
Total Nuclear decommissioning trust	$	202,483	$	107,677	$	(13,168	)	$	296,992	$	296,992

Other
Equity securities	$	82	$	24	$	—		$	106	$	106
Non-marketable equity investments		2,177		2,222		—			4,399		2,177
Total Other	$	2,259	$	2,246	$	—		$	4,505	$	2,283
										$	299,275
December 31, 2023
Nuclear decommissioning trust (1)
Debt securities	$	89,587	$	—	$	(11,626	)	$	77,961	$	77,961
Equity securities		97,056		90,539		(5,231	)		182,364		182,364
Cash and other		282		—		—			282		282
Total Nuclear decommissioning trust	$	186,925	$	90,539	$	(16,857	)	$	260,607	$	260,607

Other
Equity securities	$	125	$	12	$	—		$	137	$	137
Non-marketable equity investments		2,177		2,262		—			4,439		2,177
Total Other	$	2,302	$	2,274	$	—		$	4,576	$	2,314
										$	262,921

(1)

Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligations of the future decommissioning of North Anna. See Note 3 of the Notes to Consolidated Financial Statements in our 2023 Annual Report on Form 10-K. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or regulatory asset, respectively.

Contractual maturities of debt securities as of September 30, 2024, were as follows:



Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Other (1)	$	—	$	—	$	97,398	$	—	$	97,398
Total	$	—	$	—	$	97,398	$	—	$	97,398

(1)

The contractual maturities of other debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

Other

Revolving Credit Facility

We maintain a revolving credit facility to cover our short-term and medium-term funding needs that are not met by cash from operations or other available funds. Available funding under this facility totals $400 million and commitments under this syndicated credit agreement extend through December 7, 2028. As of September 30, 2024 and December 31, 2023, we had outstanding under this facility $55.0 million and $191.0 million in borrowings, respectively.

Revenue Recognition

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. We supply power requirements (energy and demand) to our eleven member distribution cooperatives subject to substantially identical wholesale power contracts with each of them. We bill our member distribution cooperatives monthly and each member distribution cooperative is required to pay us monthly for power furnished under its wholesale power contract. We transfer control of the electricity over time and our member distribution cooperatives simultaneously receive and consume the benefits of the electricity. The amount we invoice our member distribution cooperatives on a monthly basis corresponds directly to the value to the member distribution cooperatives of our performance, which is determined by our formula rate included in the wholesale power contract. We sell excess energy and renewable energy credits to non-members at prevailing market prices as control is transferred.

ODEC sells excess purchased and generated energy not needed to meet the actual needs of our member distribution cooperatives to PJM, TEC, or other counterparties. Our financial statements represent the consolidated financial statements of ODEC and TEC and through the consolidation process, all intercompany balances and transactions have been eliminated and TEC’s sales are reflected as non-member revenues.

Our operating revenues for the three and nine months ended September 30, 2024 and 2023, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in thousands)
Operating revenues:
Member distribution cooperatives:
Formula rate:
Energy revenues	$	139,466	$	155,828	$	406,442	$	437,988
Renewable energy credits		335		96		536		269
Demand revenues		125,827		110,922		365,818		323,566
Total Formula rate revenues		265,628		266,846		772,796		761,823
Market-based rates:
Energy revenues		11,896		5,006		29,151		12,881
Demand revenues		2,143		750		6,117		1,850
Total Market-based rates revenues		14,039		5,756		35,268		14,731

Total Member distribution cooperatives revenues		279,667		272,602		808,064		776,554

Non-members:
Energy revenues (1)		3,499		2,764		7,706		26,216
Renewable energy credits		22,613		19,195		24,104		21,844
Total Non-members revenues		26,112		21,959		31,810		48,060

Total Operating revenues	$	305,779	$	294,561	$	839,874	$	824,614

(1)

TEC did not have sales to non-members after first quarter 2023. TEC’s sales to non-members were $8.9 million for the nine months ended September 30, 2023.

Recent EPA Developments

In May 2023, the EPA proposed performance standards for both new and existing generating units for reducing carbon dioxide emissions. The proposed standards included emissions guidelines that would set limits for new gas-fired combustion turbines, existing coal, oil, and gas-fired steam generating units, and certain existing gas-fired combustion turbines.

On May 9, 2024, the final rule, which contains requirements to either retrofit existing coal units with carbon controls or retire the asset, was published in the Federal Register and became effective July 8, 2024. Also beginning on May 9, 2024, multiple lawsuits were filed against the EPA to seek judicial review of the final regulation and multiple petitions were filed seeking to stay implementation of the rule. On July 19, 2024, the United States Court of Appeals for the District of Columbia Circuit denied requests to stay the rule. On July 23, 2024, multiple entities filed an emergency stay application with the United States Supreme Court and on October 16, 2024, the United States Supreme Court denied the requests to stay the rule. The litigation continues in the United States Court of Appeals for the District of Columbia Circuit and is proceeding on an expedited schedule. We are continuing to monitor this standard as it relates to our generating facilities, particularly Clover. We will be able to determine our compliance strategies after state implementation plans have been developed related to the rule. Based on the uncertainties associated with the state implementation plans, we cannot yet determine whether the final rule will have a material adverse effect on our results of operations, financial condition, or cash flows in future periods. Further, there is no material impact on our results of operations, financial condition, or cash flows for the period ending September 30, 2024.

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. These risks, uncertainties, and other factors include, but are not limited to: general business conditions; demand for energy; federal and state legislative and regulatory actions, and legal and administrative proceedings; changes in and compliance with environmental laws and regulations; general credit and capital market conditions; weather conditions; the cost and availability of commodities used in our industry; disruption due to cybersecurity threats or incidents; 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, 2024, there have been no significant changes in our critical accounting policies as disclosed in our 2023 Annual Report on Form 10-K. These policies include the accounting for regulated operations, deferred energy, margin stabilization, accounting for asset retirement and environmental obligations, and accounting for derivatives and hedging.

Basis of Presentation

The accompanying financial statements reflect the consolidated accounts of ODEC and TEC. See “Note 1—General” in Notes to Condensed Consolidated Financial Statements in Part 1, Item 1.

Overview

We are a not-for-profit power supply cooperative owned entirely by our eleven Class A member distribution cooperatives and a Class B member, TEC. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, long-term and short-term physically-delivered forward power purchase contracts, and spot market purchases. We also supply the transmission services necessary to deliver this power to our member distribution cooperatives.

Our results from operations for the three and nine months ended September 30, 2024, as compared to the same periods in 2023, were primarily impacted by increases in purchased power expense and transmission expense, and the decrease in deferred energy expense.

•

Total revenues from sales to our member distribution cooperatives, which is comprised of sales to our member distribution cooperatives - formula rate and sales to our member distribution cooperatives - market-based rates, increased 2.6% and 4.1%, for the three and nine months ended September 30, 2024, respectively.

Total revenues from sales to our member distribution cooperatives - formula rate were relatively flat. Formula rate energy revenues decreased 10.5% and 7.2%, respectively, due to the decreases in our total energy rate, partially offset by the increase in energy sales in MWh to our member distribution cooperatives - formula rate. The weather was milder in 2023 as compared to 2024 and contributed to the increase in 2024 energy sales in MWh. Formula rate demand revenues increased 13.4% and 13.1%, respectively, substantially due to changes in PJM charges for network transmission services and higher capacity costs.

Total revenues from sales to our member distribution cooperatives - market-based rates increased 143.9% and 139.4%, respectively, due to load growth related to data centers.

•

Purchased power expense, which includes the cost of purchased energy and capacity, increased 20.2% and 10.6%, for the three and nine months ended September 30, 2024, respectively. Purchased capacity costs increased 297.3% and 191.1%, respectively, due to the increase in capacity charges from PJM. Purchased energy costs increased 8.9% and 3.9%, respectively, due to the increase in the volume of purchased energy, partially offset by the decrease in the average cost of purchased energy.

•

Transmission expense increased 14.9% and 16.3%, for the three and nine months ended September 30, 2024, respectively, primarily due to changes in PJM charges for network transmission services.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, decreased $14.7 million and $39.1 million, for the three and nine months ended September 30, 2024, respectively, due to the decreases in our total energy rate. For the three and nine months ended September 30, 2024, we over-collected $24.1 million and $47.5 million, respectively.

Factors Affecting Results

For a comprehensive discussion of factors affecting results, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Results” in Item 7 in our 2023 Annual Report on Form 10-K.

Formula Rate

Our power sales are comprised of two power products – energy and 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 demand.

The rates we charge our member distribution cooperatives are regulated by FERC and FERC has granted us authority to charge our member distribution cooperatives utilizing a formula rate and market-based rates. In accordance with our wholesale power contracts with our member distribution cooperatives, we sell power to them utilizing a formula rate. An exception in the formula rate allows our member distribution cooperatives to elect to utilize market-based rates for new and expanding loads that meet certain criteria.

The rates we charge our member distribution cooperatives under the formula rate are intended to permit collection of revenues which will equal the sum of:

•

all of our costs and expenses;

•

20% of our total interest charges (margin requirement); and

•

additional equity contributions approved by our board of directors.

The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

Our margin requirement and additional equity contributions approved by our board of directors are recovered through our demand rates. We establish our demand rates to produce a net margin attributable to ODEC equal to 20% of our budgeted total interest charges, plus additional equity contributions approved by our board of directors. The formula rate permits us to adjust revenues from the member distribution cooperatives to equal our actual total demand costs incurred, including a net margin attributable to ODEC equal to 20% of actual interest charges, plus additional equity contributions approved by our board of directors. We make these adjustments utilizing Margin Stabilization.

As detailed in the table below, we utilized Margin Stabilization to increase revenues for the three months ended September 30, 2024 and 2023, and to reduce revenues for the nine months ended September 30, 2024 and 2023.


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024		2023
	(in thousands)
Margin Stabilization adjustment	$	(1,606	)	$	(1,844	)	$	6,357	$	2,293

For further discussion of Margin Stabilization, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Margin Stabilization” in Item 7 in our 2023 Annual Report on Form 10-K.

Weather

Weather affects the demand for electricity. Relatively higher or lower temperatures tend to increase the demand for energy to use air conditioning and heating systems, respectively. Mild weather generally reduces the demand because heating and air conditioning systems are operated less. Weather also plays a role in the price of energy through its effects on the market price for fuel, particularly natural gas.

Heating and cooling degree days are measurement tools used to quantify the need to utilize heating or cooling, respectively, for a building. Heating degree days are calculated as the number of degrees below 60 degrees in a single day. Cooling degree days are calculated as the number of degrees above 65 degrees in a single day. In a single calendar day, it is possible to have multiple heating degree and cooling degree days.

The heating and cooling degree days for the three and nine months ended September 30, 2024, were as follows:


	Three Months Ended September 30,							Nine Months Ended September 30,
	2024		2023		Change			2024		2023		Change
Heating degree days		—		—	—		%		1,856		1,610		15.3	%
Cooling degree days		929		928		0.1			1,308		1,062		23.2

Power Supply Resources

We provide power to our members through a combination of our interests in Wildcat Point, a natural gas-fired combined cycle generation facility; North Anna, a nuclear power station; Clover, a coal-fired generation facility; two natural gas-fired combustion turbine facilities (Louisa and Marsh Run); diesel-fired distributed generation facilities; and physically-delivered forward power purchase contracts and spot market energy purchases. Our energy supply resources for the three and nine months ended September 30, 2024 and 2023, were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
	(in MWh and percentages)
Generated:
Wildcat Point	920,826	24.2	%	1,305,708	37.6	%	2,271,964	21.2	%	3,466,453	35.5	%
North Anna	487,950	12.8		423,993	12.2		1,359,501	12.7		1,405,412	14.4
Clover	104,945	2.8		63,310	1.8		361,713	3.4		98,799	1.0
Louisa	222,382	5.9		61,687	1.8		383,263	3.6		152,266	1.6
Marsh Run	205,423	5.4		57,890	1.7		329,615	3.1		128,856	1.3
Distributed Generation	934	—		1,302	—		1,955	—		2,355	—
Total Generated	1,942,460	51.1		1,913,890	55.1		4,708,011	44.0		5,254,141	53.8
Purchased:
Other than renewable:
Long-term and short-term	618,851	16.3		766,071	22.1		2,390,637	22.4		2,652,358	27.1
Spot market	1,096,577	28.8		682,471	19.6		3,038,594	28.4		1,368,560	14.0
Total Other than renewable	1,715,428	45.1		1,448,542	41.7		5,429,231	50.8		4,020,918	41.1
Renewable (1)	144,394	3.8		111,450	3.2		555,802	5.2		498,142	5.1
Total Purchased	1,859,822	48.9		1,559,992	44.9		5,985,033	56.0		4,519,060	46.2
Total Available Energy	3,802,282	100.0	%	3,473,882	100.0	%	10,693,044	100.0	%	9,773,201	100.0	%

(1)

Related to our contracts from renewable facilities from which we obtain renewable energy credits. We may sell these renewable energy credits to our member distribution cooperatives and non-members.

Generating Facilities

Our operating expenses, and consequently our rates charged to our member distribution cooperatives, are significantly affected by the operations of our generating facilities, which are under dispatch direction of PJM. PJM balances its members’ power requirements with the power resources available to supply those requirements. Based on this evaluation of supply and demand, PJM schedules and directs the dispatch of available generating facilities throughout its region in a manner intended to meet the demand for energy in the most reliable and cost-effective manner. Thus, PJM directs the dispatch of these facilities even though it does not own them. For further discussion of PJM, see “Business—Power Supply Resources—PJM” in Item 1 in our 2023 Annual Report on Form 10-K.

Operational Availability

The operational availability of our owned generating resources for the three and nine months ended September 30, 2024 and 2023, was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
Wildcat Point		99.5	%		99.2	%		92.0	%		91.6	%
North Anna		100.0			87.7			93.0			95.8
Clover		76.8			93.2			73.0			70.9
Louisa		98.5			99.9			97.5			98.6
Marsh Run		99.1			99.8			93.3			94.5

Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the three and nine months ended September 30, 2024 and 2023, as a percentage of maximum dependable capacity rating of the facilities, was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
Wildcat Point		42.5	%		60.4	%		35.1	%		54.0	%
North Anna		100.7			87.5			94.2			97.7
Clover		11.4			6.9			13.1			3.6

North Anna

On August 28, 2024, the Nuclear Regulatory Commission renewed the operating licenses for an additional 20 years for both units at North Anna. The operating licenses now extend through April 1, 2058, and August 21, 2060, for North Anna Unit 1 and Unit 2, respectively.

Results of Operations

Operating Revenues

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. ODEC sells excess purchased and generated energy not needed to meet the actual needs of our member distribution cooperatives to PJM, TEC, or other counterparties. Our financial statements represent the consolidated financial statements of ODEC and TEC and through the consolidation process, all intercompany balances and transactions have been eliminated and TEC’s sales are reflected as non-member revenues. Our operating revenues and energy sales in MWh by type of purchaser for the three and nine months ended September 30, 2024 and 2023, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in thousands)
Operating revenues:
Member distribution cooperatives:
Formula rate	$	265,628	$	266,846	$	772,796	$	761,823
Market-based rates		14,039		5,756		35,268		14,731
Total Member distribution cooperatives		279,667		272,602		808,064		776,554

Non-members (1)		26,112		21,959		31,810		48,060
Total Operating revenues	$	305,779	$	294,561	$	839,874	$	824,614

Energy sales to:	(in MWh)
Member distribution cooperatives - formula rate		3,377,704		3,178,754		9,617,305		8,400,761
Member distribution cooperatives - market-based rates		303,873		138,839		790,331		368,720
Non-members		69,389		124,356		199,639		932,951
Total Energy sales		3,750,966		3,441,949		10,607,275		9,702,432

(1)

TEC did not have sales to non-members after first quarter 2023. TEC’s sales to non-members were $8.9 million for the nine months ended September 30, 2023.

Member Distribution Cooperatives

Formula Rate

Our operating revenues from sales to member distribution cooperatives - formula rate for the three and nine months ended September 30, 2024 and 2023, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in thousands)
Member distribution cooperatives:
Formula rate:
Energy revenues	$	139,466	$	155,828	$	406,442	$	437,988
Renewable energy credits		335		96		536		269
Demand revenues		125,827		110,922		365,818		323,566
Total Formula rate revenues	$	265,628	$	266,846	$	772,796	$	761,823

Energy sales to:	(in MWh)
Member distribution cooperatives - formula rate		3,377,704		3,178,754		9,617,305		8,400,761

Average cost to member distribution cooperatives:	(per MWh)
Formula rate energy cost	$	41.29	$	49.02	$	42.26	$	52.14
Formula rate total cost	$	78.64	$	83.95	$	80.35	$	90.68

For the three and nine months ended September 30, 2024, total formula rate revenues were relatively flat as compared to the same periods in 2023. Formula rate energy revenues decreased $16.4 million, or 10.5%, and $31.5 million, or 7.2%, respectively, due to the decreases in our total energy rate, partially offset by the 6.3% and 14.5%, increase in energy sales in MWh to our member distribution cooperatives - formula rate, respectively. The weather was milder in 2023 as compared to 2024 and contributed to the increase in 2024 energy sales in MWh. Formula rate demand revenues increased $14.9 million, or 13.4%, and $42.3 million, or 13.1%, respectively, substantially due to changes in PJM charges for network transmission services and higher capacity costs.

The following table summarizes the changes to our total energy rate since 2023, which were implemented to address the differences in our realized as well as projected energy costs:


Date	% Change
January 1, 2023		(1.5	)
August 1, 2023		(14.8	)
January 1, 2024		(7.0	)
July 1, 2024		(3.5	)

Market-based Rates

Our operating revenues from sales to member distribution cooperatives - market-based rates for the three and nine months ended September 30, 2024 and 2023, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
Member distribution cooperatives:	(in thousands)
Market-based rates:
Energy revenues	$	11,896	$	5,006	$	29,151	$	12,881
Demand revenues		2,143		750		6,117		1,850
Total Market-based rates revenues	$	14,039	$	5,756	$	35,268	$	14,731

Energy sales to:	(in MWh)
Member distribution cooperatives - market-based rates		303,873		138,839		790,331		368,720

The increase in total market-based rates revenues is a result of load growth related to data centers. See "Member Distribution Cooperatives" above.

Operating Expenses

The following is a summary of the components of our operating expenses for the three and nine months ended September 30, 2024 and 2023:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2024		2023		2024		2023
	(in thousands)
Fuel	$	52,096	$	47,502	$	151,705	$	148,335
Purchased power		107,270		89,222		272,528		246,492
Transmission		51,058		44,442		150,110		129,030
Deferred energy		24,122		38,865		47,485		86,557
Operations and maintenance		22,475		25,709		69,770		67,196
Administrative and general		12,536		10,879		37,108		32,121
Depreciation and amortization		17,600		17,439		52,616		52,104
Amortization of regulatory asset/(liability), net		920		634		12,475		1,121
Accretion of asset retirement obligations		1,573		1,520		4,716		4,557
Taxes, other than income taxes		2,323		2,244		6,944		6,837
Total operating expenses	$	291,973	$	278,456	$	805,457	$	774,350

Our operating expenses are comprised of the costs that we incur to generate and purchase power to meet the needs of our member distribution cooperatives, and the costs associated with any sales of power to non-members. Our energy costs generally are variable and include fuel expense, the energy portion of our purchased power expense, and the variable portion of operations and maintenance expense. Our demand costs generally are fixed and include the capacity portion of our purchased power expense, transmission expense, the fixed portion of operations and maintenance expense, administrative and general expense, and depreciation and amortization expense. Additionally, all non-operating expenses and income items, including investment income and interest charges, net, are components of our demand costs. See “Factors Affecting Results—Formula Rate” above.

Total operating expenses increased $13.5 million, or 4.9%, and $31.1 million, or 4.0%, for the three and nine months ended September 30, 2024, respectively, as compared to the same periods in 2023, primarily as a result of increases in purchased power expense and transmission expense, partially offset by the decrease in deferred energy expense.

•

Purchased power expense, which includes the cost of purchased energy and capacity, increased $18.0 million, or 20.2%, and $26.0 million, or 10.6%, for the three and nine months ended September 30, 2024, respectively. Purchased capacity costs increased $10.4 million, or 297.3%, and $16.8 million, or 191.1%, respectively, due to the increase in capacity charges from PJM. Purchased energy costs increased $7.6 million, or 8.9%, and $9.3 million, or 3.9%, respectively, due to the 19.2% and 32.4% increase in the volume of purchased energy, partially offset by the 8.6% and 21.6% decrease in the average cost of purchased energy.

•

Transmission expense increased $6.6 million, or 14.9%, and $21.1 million, or 16.3%, for the three and nine months ended September 30, 2024, respectively, primarily due to changes in PJM charges for network transmission services.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, decreased $14.7 million and $39.1 million, for the three and nine months ended September 30, 2024, respectively, due to the decreases in our total energy rate. For further discussion on deferred energy, see "Management's Discussion and Analysis of Financial Condition and Results of Operations—Deferred Energy" in Item 7 in our 2023 Annual Report on Form 10-K.

Other Items

Interest Charges, Net

The primary factors affecting our interest charges, net are issuances of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility (including fees), and interest paid to our member distribution cooperatives on prepayment balances. The major components of interest charges, net for the three and nine months ended September 30, 2024 and 2023, were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2024			2023			2024			2023
	(in thousands)
Interest on long-term debt	$	(11,625	)	$	(12,311	)	$	(34,860	)	$	(36,919	)
Interest on revolving credit facility		(1,436	)		(1,806	)		(6,223	)		(5,680	)
Other interest		(1,215	)		(1,661	)		(3,954	)		(5,054	)
Total interest charges		(14,276	)		(15,778	)		(45,037	)		(47,653	)
Allowance for borrowed funds used during construction		584			352			1,702			1,019
Interest charges, net	$	(13,692	)	$	(15,426	)	$	(43,335	)	$	(46,634	)

Net Margin Attributable to ODEC

Net margin attributable to ODEC, which is a function of our total interest charges plus any additional equity contributions approved by our board of directors, was 9.5% and 5.5% lower for the three and nine months ended September 30, 2024, respectively, as compared to the same periods in 2023, due to the decrease in total interest charges.

Financial Condition

The principal changes in our financial condition from December 31, 2023 to September 30, 2024, were caused by increases in accounts payable–members, deferred energy, nuclear decommissioning trust, and regulatory liabilities; substantially offset by the decrease in revolving credit facility.

•

Accounts payable–members increased $75.3 million due to the $72.1 million increase in member prepayments and the $3.1 million increase in the amounts owed to our member distribution cooperatives under Margin Stabilization.

•

Deferred energy increased $47.5 million due to the over-collection of our energy costs in 2024.

•

Nuclear decommissioning trust increased $36.4 million due to the $20.8 million increase in the fair value of the fund and the $15.6 million realized gain and earnings on the fund.

•

Regulatory liabilities increased $31.5 million primarily due to the change in the unrealized gain on the nuclear decommissioning trust and the increase in derivatives.

•

Revolving credit facility decreased $136.0 million due to the increase in cash provided by operating activities.

Liquidity and Capital Resources

Sources

Cash generated by our operations, periodic borrowings under our revolving credit facility, and occasional issuances of long-term debt provide our sources of liquidity and capital.

Operations

During the first nine months of 2024 and 2023, our operating activities provided cash flows of $249.3 million and $61.8 million, respectively.

Revolving Credit Facility

Financings

We fund the portion of our capital expenditures that we are not able to fund from operations through borrowings under our revolving credit facility and issuances of debt in the capital markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, or improvement of our owned generating and transmission facilities. We continue to evaluate the issuance of additional long-term indebtedness in the near term to fund capital expenditures related to our existing generating and transmission facilities. Additionally, we are evaluating the need to construct new generating facilities, which could result in the issuance of additional long-term indebtedness. We believe our cash from operations, funds available from our revolving credit facility, and issuances of additional long-term indebtedness, will be sufficient to meet our currently anticipated future operational and capital requirements.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities, and financing activities. Substantially all of our investment activities relate to capital expenditures in connection with our generating facilities. Additionally, we have asset retirement obligations in the future that are significantly offset by the nuclear decommissioning trust, which as of September 30, 2024, had a balance of $297.0 million. Our future contingent obligations primarily relate to power purchase and natural gas arrangements, and we have no off-balance sheet obligations. Some of our power purchase contracts obligate us to provide credit support if our obligations issued under the Indenture are rated below specified thresholds by S&P and Moody’s. We currently anticipate that cash from operations, borrowings under our revolving credit facility, and potential issuances of long-term indebtedness will be sufficient to meet our liquidity needs for the near term, including planned capital expenditures, decommissioning trust obligations, and our contingent obligations as described above.

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the third quarter of 2024.

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 manner. We have established a Disclosure Assessment Committee comprised of members of our senior and middle management to assist in this evaluation.

There have been no material changes in our internal control over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter.

OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Other Matters

Other than certain legal proceedings arising out of the ordinary course of business that 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 1A. RISK FACTORS

In addition to the other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A in our 2023 Annual Report on Form 10-K, which could affect our business, results of operations, financial condition, and cash flows. The risks described in our Annual Report on Form 10-K are not the only risks facing us. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, results of operations, financial condition, and cash flows.

ITEM 5. OTHER INFORMATION

During the fiscal quarter ended September 30, 2024, none of our directors or officers informed us of the adoption or termination of a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as those terms are defined in Item 408 of Regulation S-K. We have debt securities but no equity securities outstanding because we are a cooperative. See “Business—Overview” in Item 1 in our 2023 Annual Report on Form 10-K.

Mr. Kirk D. Johnson ceased to serve as Senior Vice President of Member Relations at ODEC effective November 5, 2024.

Recent EPA Developments

ITEM 6. EXHIBITS



31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a)
31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a)
32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350
101.INS		Inline XBRL Instance Document (the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document)
101.SCH		Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Documents
104		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101)

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, 2024		/s/ BRYAN S. ROGERS
		Bryan S. Rogers
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)