Q10000885568--12-31falsehttp://fasb.org/us-gaap/2025#ElectricityMemberhttp://fasb.org/us-gaap/2025#ElectricityMember0000885568ck0000885568:NuclearDecommissioningTrustNetAssetValueMember2025-12-3100008855682025-03-310000885568us-gaap:RevolvingCreditFacilityMember2026-03-310000885568ck0000885568:NuclearDecommissioningTrustMember2025-12-310000885568ck0000885568:DerivativeInstrumentFuelRegulatoryAssetLiabilityMemberus-gaap:CommodityContractMembersrt:FuelMember2026-03-310000885568ck0000885568:DerivativeInstrumentFuelRegulatoryAssetLiabilityMemberus-gaap:CommodityContractMembersrt:FuelMember2025-03-310000885568ck0000885568:DerivativeInstrumentFuelMemberus-gaap:CommodityContractMembersrt:FuelMember2025-01-012025-03-310000885568us-gaap:ElectricityPurchasedMemberck0000885568:FinancialTransmissionRightsMember2026-01-012026-03-310000885568us-gaap:FairValueInputsLevel2Memberck0000885568:UnrestrictedInvestmentAndOtherMember2026-03-310000885568us-gaap:FairValueInputsLevel2Memberck0000885568:UnrestrictedInvestmentAndOtherMember2025-12-310000885568us-gaap:OtherAssetsMemberck0000885568:FinancialTransmissionRightsMember2026-03-310000885568ck0000885568:FinancialTransmissionRightsMember2026-01-012026-03-310000885568us-gaap:FairValueInputsLevel1Memberck0000885568:NuclearDecommissioningTrustMember2025-12-310000885568us-gaap:FairValueInputsLevel1Memberck0000885568:NuclearDecommissioningTrustMember2026-03-310000885568ck0000885568:NuclearDecommissioningTrustMember2026-03-310000885568ck0000885568:ZeroEmissionNuclearProductionTaxCreditMember2025-12-310000885568ck0000885568:DerivativeInstrumentPurchasedPowerRegulatoryAssetLiabilityMemberus-gaap:ElectricityPurchasedMemberck0000885568:FinancialTransmissionRightsMember2025-03-310000885568us-gaap:FairValueInputsLevel2Member2026-03-310000885568us-gaap:FairValueInputsLevel3Member2026-03-310000885568us-gaap:OtherAssetsMemberus-gaap:CommodityContractMember2026-03-310000885568us-gaap:DerivativeMember2026-03-310000885568us-gaap:FairValueInputsLevel2Memberus-gaap:DerivativeMember2026-03-310000885568ck0000885568:NuclearDecommissioningTrustMember2026-03-310000885568us-gaap:FairValueInputsLevel1Memberus-gaap:DerivativeMember2026-03-310000885568ck0000885568:NuclearDecommissioningTrustNetAssetValueMember2026-03-310000885568us-gaap:LetterOfCreditMember2026-03-310000885568ck0000885568:UnrestrictedInvestmentAndOtherMember2025-12-310000885568ck0000885568:OtherInvestmentMember2026-03-310000885568us-gaap:FairValueInputsLevel2Member2025-12-310000885568ck0000885568:ZeroEmissionNuclearProductionTaxCreditMember2026-03-310000885568us-gaap:VariableInterestEntityPrimaryBeneficiaryMember2026-03-310000885568ck0000885568:OtherInvestmentMember2025-12-3100008855682025-01-012025-03-310000885568us-gaap:FairValueInputsLevel3Memberus-gaap:DerivativeMember2025-12-310000885568us-gaap:VariableInterestEntityPrimaryBeneficiaryMember2025-12-3100008855682024-12-310000885568ck0000885568:UnrestrictedInvestmentAndOtherMember2026-03-310000885568us-gaap:FairValueInputsLevel1Member2026-03-310000885568us-gaap:FairValueInputsLevel1Member2025-12-310000885568us-gaap:OtherAssetsMemberus-gaap:CommodityContractMember2025-12-310000885568srt:NaturalGasReservesMember2025-01-012025-12-310000885568us-gaap:OtherAssetsMemberck0000885568:FinancialTransmissionRightsMember2025-12-310000885568us-gaap:FairValueInputsLevel3Memberus-gaap:DerivativeMember2026-03-310000885568us-gaap:DebtInstrumentRedemptionPeriodTwoMemberus-gaap:RevolvingCreditFacilityMember2026-03-310000885568ck0000885568:FinancialTransmissionRightsMember2025-01-012025-12-310000885568us-gaap:DerivativeMember2025-12-3100008855682025-12-310000885568us-gaap:ElectricityPurchasedMemberck0000885568:FinancialTransmissionRightsMember2025-01-012025-03-310000885568us-gaap:CommodityContractMemberus-gaap:OtherLiabilitiesMember2026-03-310000885568srt:NaturalGasReservesMember2026-01-012026-03-310000885568us-gaap:FairValueInputsLevel1Memberus-gaap:DerivativeMember2025-12-310000885568ck0000885568:DerivativeInstrumentFuelMemberus-gaap:CommodityContractMembersrt:FuelMember2026-01-012026-03-310000885568us-gaap:CommodityContractMemberus-gaap:OtherLiabilitiesMember2025-12-3100008855682026-01-012026-03-310000885568ck0000885568:DerivativeInstrumentPurchasedPowerRegulatoryAssetLiabilityMemberus-gaap:ElectricityPurchasedMemberck0000885568:FinancialTransmissionRightsMember2026-03-310000885568us-gaap:LetterOfCreditMember2025-12-310000885568us-gaap:FairValueInputsLevel2Memberus-gaap:DerivativeMember2025-12-310000885568ck0000885568:NuclearDecommissioningTrustMember2025-12-3100008855682026-03-310000885568us-gaap:RevolvingCreditFacilityMember2025-12-310000885568us-gaap:FairValueInputsLevel3Member2025-12-31ck0000885568:Memberxbrli:sharesutr:MMBTUck0000885568:Representativeck0000885568:Member_classutr:MWhiso4217:USD

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 March 31, 2026


☐	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

CO2		Carbon dioxide

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States

IRS		Internal Revenue Service

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

RGGI		Regional Greenhouse Gas Initiative

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 – March 31, 2026 (unaudited) and December 31, 2025		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three Months Ended March 31, 2026 and 2025		5

Condensed Consolidated Statements of Cash Flows (unaudited) – Three Months Ended March 31, 2026 and 2025		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		22

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


	March 31, 2026			December 31, 2025
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,615,500		$	2,616,856
Less accumulated depreciation		(1,302,749	)		(1,292,398	)
Net Property, plant, and equipment		1,312,751			1,324,458
Nuclear fuel, at amortized cost		16,272			19,183
Construction work in progress		196,679			157,532
Net Electric Plant		1,525,702			1,501,173
Investments:
Nuclear decommissioning trust		333,273			340,568
Unrestricted investments and other		2,298			2,270
Total Investments		335,571			342,838
Current Assets:
Cash and cash equivalents		85,003			168,449
Accounts receivable		56,798			50,058
Accounts receivable–members		114,289			156,093
Fuel, materials, and supplies		142,174			99,585
Deferred energy		89,560			—
Prepayments and other		10,090			16,599
Total Current Assets		497,914			490,784
Deferred Charges and Other Assets:
Regulatory assets		16,048			8,866
Other assets		38,722			37,625
Total Deferred Charges and Other Assets		54,770			46,491
Total Assets	$	2,413,957		$	2,381,286
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	558,940		$	549,142
Non-controlling interest		6,977			6,937
Total Patronage capital and Non-controlling interest		565,917			556,079
Long-term debt		1,074,750			1,074,652
Revolving credit facility		50,000			—
Total Long-term debt and Revolving credit facility		1,124,750			1,074,652
Total Capitalization		1,690,667			1,630,731
Current Liabilities:
Long-term debt due within one year		49,041			49,041
Accounts payable		119,819			130,494
Accounts payable–members		41,469			15,349
Accrued expenses		20,944			5,942
Deferred energy		—			59,025
Total Current Liabilities		231,273			259,851
Deferred Credits and Other Liabilities:
Asset retirement obligations		218,583			216,791
Regulatory liabilities		250,091			256,163
Other liabilities		23,343			17,750
Total Deferred Credits and Other Liabilities		492,017			490,704
Total Capitalization and Liabilities	$	2,413,957		$	2,381,286

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 March 31,
	2026			2025
	(in thousands)
Operating Revenues	$	410,850		$	323,610
Operating Expenses:
Fuel		165,546			93,729
Purchased power		250,755			157,622
Transmission		61,039			60,290
Deferred energy		(148,585	)		(66,814	)
Operations and maintenance		24,781			24,260
Administrative and general		14,952			13,954
Depreciation and amortization		17,441			17,708
Amortization of regulatory asset/(liability), net		1,176			(158	)
Accretion of asset retirement obligations		1,792			1,729
Taxes, other than income taxes		2,294			2,308
Total Operating Expenses		391,191			304,628
Operating Margin		19,659			18,982
Other income (expense), net		(128	)		(94	)
Investment income		3,841			3,155
Interest charges, net		(13,520	)		(12,478	)
Income tax expense		(14	)		(13	)
Net Margin including Non-controlling interest		9,838			9,552
Non-controlling interest		(40	)		(39	)
Net Margin attributable to ODEC		9,798			9,513
Patronage Capital - Beginning of Period		549,142			500,407
Patronage Capital - End of Period	$	558,940		$	509,920

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)


	Three Months Ended March 31,
	2026			2025
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	9,838		$	9,552
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		17,441			17,708
Other non-cash charges		4,802			4,200
Change in current assets		(1,016	)		7,979
Change in deferred energy		(148,585	)		(66,814	)
Change in current liabilities		40,814			33,377
Change in regulatory assets and liabilities		(3,508	)		46,550
Change in other assets and other liabilities		4,498			(787	)
Net Cash (Used for) Provided by Operating Activities		(75,716	)		51,765
Investing Activities:
Increase in other investments		(2,481	)		(1,042	)
Electric plant additions		(55,249	)		(19,018	)
Net Cash Used for Investing Activities		(57,730	)		(20,060	)
Financing Activities:
Draws on revolving credit facility		50,000			83,000
Repayments on revolving credit facility		—			(98,000	)
Net Cash Provided by (Used for) Financing Activities		50,000			(15,000	)
Net Change in Cash and Cash Equivalents		(83,446	)		16,705
Cash and Cash Equivalents - Beginning of Period		168,449			40,689
Cash and Cash Equivalents - End of Period	$	85,003		$	57,394

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 March 31, 2026, our consolidated results of operations for the three months ended March 31, 2026 and 2025, and cash flows for the three months ended March 31, 2026 and 2025. The consolidated results of operations for the three months ended March 31, 2026, 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 2025 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 $7.0 million and $6.9 million as of March 31, 2026 and December 31, 2025, 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 March 31, 2026 and December 31, 2025:


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
	As of		Identical		Observable		Unobservable
	March 31,		Assets		Inputs		Inputs
	2026		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	301	$	301	$	—	$	—
Nuclear decommissioning trust - net asset value (1)(2)		332,972		—		—		—
Unrestricted investments and other (3)		114		—		114		—
Derivatives - gas and power (4)		11,322		—		389		10,933
Total financial assets	$	344,709	$	301	$	503	$	10,933

Derivatives - gas and power (4)	$	18,199	$	17,971	$	228	$	—
Total financial liabilities	$	18,199	$	17,971	$	228	$	—


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
	As of		Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs
	2025		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	366	$	366	$	—	$	—
Nuclear decommissioning trust - net asset value (1)(2)		340,202		—		—		—
Unrestricted investments and other (3)		86		—		86		—
Derivatives - gas and power (4)		16,365		—		472		15,893
Total financial assets	$	357,019	$	366	$	558	$	15,893

Derivatives - gas and power (4)	$	13,360	$	13,125	$	235	$	—
Total financial liabilities	$	13,360	$	13,125	$	235	$	—

(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 2025 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 2025 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 March 31,		As of December 31,
Commodity	Unit of Measure	2026		2025
Natural gas	MMBTU		115,240,000		105,060,000
Purchased power - financial transmission rights	MWh		5,446,034		7,247,703

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


		Fair Value
		As of March 31,		As of December 31,
	Balance Sheet Location	2026		2025
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	389	$	472
Financial transmission rights	Other assets		10,933		15,893
Total Derivatives in an asset position		$	11,322	$	16,365

Derivatives in a liability position:
Natural gas futures contracts	Other liabilities	$	18,199	$	13,360
Total Derivatives in a liability position		$	18,199	$	13,360

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three Months Ended March 31, 2026 and 2025


	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
Accounted for Utilizing	Derivatives as of						Asset/Liability	Ended
Regulatory Accounting	March 31,						into Income	March 31,
	2026			2025				2026		2025
	(in thousands)							(in thousands)
Natural gas futures contracts	$	(18,789	)	$	19,252		Fuel	$	17,203	$	8,741
Purchased power		10,933			(8	)	Purchased power		2,258		(5,158	)
Total	$	(7,856	)	$	19,244		Total	$	19,461	$	3,583

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 March 31, 2026 and December 31, 2025:


			Gross		Gross
			Unrealized		Unrealized			Fair		Carrying
Description	Cost		Gains		Losses			Value		Value
	(in thousands)
March 31, 2026
Nuclear decommissioning trust (1)
Debt securities	$	100,579	$	1,259	$	—		$	101,838	$	101,838
Equity securities		98,885		132,701		(452	)		231,134		231,134
Cash and other		301		—		—			301		301
Total Nuclear decommissioning trust	$	199,765	$	133,960	$	(452	)	$	333,273	$	333,273

Other
Equity securities	$	105	$	9	$	—		$	114	$	114
Non-marketable equity investments		2,184		1,818		—			4,002		2,184
Total Other	$	2,289	$	1,827	$	—		$	4,116	$	2,298
										$	335,571
December 31, 2025
Nuclear decommissioning trust (1)
Debt securities	$	99,388	$	2,471	$	—		$	101,859	$	101,859
Equity securities		97,560		141,444		(661	)		238,343		238,343
Cash and other		366		—		—			366		366
Total Nuclear decommissioning trust	$	197,314	$	143,915	$	(661	)	$	340,568	$	340,568

Other
Equity securities	$	75	$	11	$	—		$	86	$	86
Non-marketable equity investments		2,184		2,188		—			4,372		2,184
Total Other	$	2,259	$	2,199	$	—		$	4,458	$	2,270
										$	342,838

(1)

Investments in the nuclear decommissioning trust are restricted for the use of funding our share of the asset retirement obligation of the future decommissioning of North Anna. See Note 3 of the Notes to Consolidated Financial Statements in our 2025 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 March 31, 2026, were as follows:



Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Other (1)	$	—	$	—	$	101,838	$	—	$	101,838
Total	$	—	$	—	$	101,838	$	—	$	101,838

(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. The $400 million in aggregate commitments under this credit agreement mature on December 7, 2028, unless earlier terminated in accordance with the agreement. As of March 31, 2026, we had outstanding under this facility $50.0 million in borrowings. As of December 31, 2025, we did not have any borrowings outstanding under this facility. As of March 31, 2026, and December 31, 2025, we did not have any letters of credit outstanding under this facility.

Zero-emission Nuclear Power Production Tax Credit

The Inflation Reduction Act of 2022 provides for the zero-emission nuclear power production tax credit for electricity produced at a qualified nuclear power facility, including North Anna, and sold to an unrelated third party beginning in 2024. In 2025, we established a receivable as well as a regulatory liability for $43.5 million. In the first quarter of 2026, we accrued an additional $7.6 million for a total of $51.1 million. The ultimate zero-emission nuclear power production tax credit realized by us may vary significantly based on future IRS guidance. For additional information, see Note 1 of the Notes to Consolidated Financial Statements in our 2025 Annual Report on Form 10-K.

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.

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.

Our operating revenues for the three months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Operating revenues:
Member distribution cooperatives:
Formula rate:
Energy revenues	$	174,614	$	148,284
Renewable energy credits		97		306
Demand revenues		133,711		141,463
Total Formula rate revenues		308,422		290,053
Market-based rates:
Energy revenues		79,073		23,804
Demand revenues		12,751		3,501
Total Market-based rates revenues		91,824		27,305

Total Member distribution cooperatives revenues		400,246		317,358

Non-members:
Energy revenues		6,805		5,166
Renewable energy credits		3,799		1,086
Total Non-members revenues		10,604		6,252

Total Operating revenues	$	410,850	$	323,610

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; change in load requirements; 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 March 31, 2026, there have been no significant changes in our critical accounting policies as disclosed in our 2025 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 months ended March 31, 2026, as compared to the same period in 2025, were primarily impacted by the increase in total revenues from sales to our member distribution cooperatives, increases in purchased power expense and fuel expense, and the decrease in deferred energy expense. In January and February of 2026, the PJM region experienced periods of extremely cold weather, which increased our member distribution cooperatives’ customers’ requirements for power as well as increased our purchased power and fuel expenses. As a result, our deferred energy balance changed from an over-collection of energy costs as of December 31, 2025, to an under-collection of energy costs as of March 31, 2026.

•

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 26.1%.

•

Total revenues from sales to our member distribution cooperatives - formula rate increased 6.3%.

•

Formula rate energy revenues increased 17.8% due to changes in our total energy rate and the increase in energy sales in MWh.

•

Formula rate demand revenues decreased 5.5% substantially due to the decrease in purchased capacity costs charged to load served under the formula rate.

•

Total revenues from sales to our member distribution cooperatives - market-based rates increased 236.3% due to load growth related to increased member distribution cooperative sales to data centers.

•

Purchased power expense, which includes the cost of purchased energy and capacity, increased 59.1%.

•

Purchased energy costs increased 66.0% due to increases in the average cost and volume of purchased energy.

•

The average cost of purchased energy increased 55.4%.

•

The volume of purchased energy increased 6.8% primarily due to the increase in purchased energy in MWh for market-based rates sales.

•

Purchased capacity costs decreased 10.2%.

•

Fuel expense increased 76.6%. The average cost of fuel increased 58.9%, and generation from our owned facilities increased 11.2%.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, decreased $81.8 million. For the three months ended March 31, 2026, we under-collected $148.6 million primarily as a result of the periods of extreme cold weather in January and February of 2026. Our deferred energy balance changed from an over-collection of $59.0 million as of December 31, 2025, to an under-collection of $89.6 million as of March 31, 2026. To address the under-collection of energy costs, our board of directors approved an increase of 24.1% to our total energy rate, effective May 1, 2026.

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 2025 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 both 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 reduce revenues for the three months ended March 31, 2026, and to increase revenues for the three months ended March 31, 2025.


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Margin Stabilization adjustment	$	6,996	$	(1,883	)

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 2025 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 for energy 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 months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026		2025		Change
Heating degree days		2,056		2,068		(0.6	)%
Cooling degree days		—		—	—

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 months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026			2025
	(in MWh and percentages)
Generated:
Wildcat Point	843,939	17.9	%	756,502	17.4	%
North Anna	490,530	10.4		408,511	9.4
Clover	225,542	4.8		227,722	5.2
Louisa	174,837	3.7		137,920	3.2
Marsh Run	154,450	3.3		168,444	3.9
Distributed Generation	848	—		1,126	—
Total Generated	1,890,146	40.1		1,700,225	39.1
Purchased:
Other than renewable:
Long-term and short-term	1,442,995	30.6		1,278,611	29.4
Spot market (1)	1,112,579	23.6		1,089,120	25.1
Total Other than renewable	2,555,574	54.2		2,367,731	54.5
Renewable (2)	271,381	5.7		279,010	6.4
Total Purchased	2,826,955	59.9		2,646,741	60.9
Total Available Energy	4,717,101	100.0	%	4,346,966	100.0	%

(1)

Includes purchases for formula rate and market-based rates sales.

(2)

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 2025 Annual Report on Form 10-K.

Operational Availability

The operational availability of our owned generating resources for the three months ended March 31, 2026 and 2025, was as follows:


	Three Months Ended March 31,
	2026			2025
Wildcat Point		99.5	%		97.1	%
North Anna		100.0			83.4
Clover		67.3			60.1
Louisa		98.5			96.4
Marsh Run		86.3			96.0

The operational availability is impacted by planned maintenance outages as well as unplanned outages.

Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the three months ended March 31, 2026 and 2025, as a percentage of maximum dependable capacity rating of the respective facility, was as follows:


	Three Months Ended March 31,
	2026			2025
Wildcat Point		39.7	%		35.6	%
North Anna		103.5			86.2
Clover		25.8			24.8

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 months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Operating revenues:
Member distribution cooperatives:
Formula rate	$	308,422	$	290,053
Market-based rates		91,824		27,305
Total Member distribution cooperatives		400,246		317,358

Non-members (1)		10,604		6,252
Total Operating revenues	$	410,850	$	323,610

Energy sales to:	(in MWh)
Member distribution cooperatives - formula rate		3,924,155		3,836,308
Member distribution cooperatives - market-based rates		705,574		388,567
Non-members		77,785		104,262
Total Energy sales		4,707,514		4,329,137

(1)

Includes renewable energy credit sales of $3.8 million and $1.0 million for the three months ended March 31, 2026 and March 31, 2025, respectively.

Member Distribution Cooperatives

Formula Rate

Our operating revenues from sales to member distribution cooperatives - formula rate for the three months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Member distribution cooperatives:
Formula rate:
Energy revenues	$	174,614	$	148,284
Renewable energy credits		97		306
Demand revenues		133,711		141,463
Total Formula rate revenues	$	308,422	$	290,053

Energy sales to:	(in MWh)
Member distribution cooperatives - formula rate		3,924,155		3,836,308

Average cost to member distribution cooperatives:	(per MWh)
Formula rate energy cost	$	44.50	$	38.65
Formula rate total cost	$	78.60	$	75.61

For the three months ended March 31, 2026, total formula rate revenues increased $18.4 million, or 6.3%, as compared to the same period in 2025.

•

Formula rate energy revenues increased $26.3 million, or 17.8%, due to changes in our total energy rate, and the 2.3% increase in energy sales in MWh.

•

Formula rate demand revenues decreased $7.8 million, or 5.5%, substantially due to the decrease in purchased capacity costs charged to load served under the formula rate.

The following table summarizes the changes to our total energy rate since 2025 to address the differences in our realized as well as projected energy costs:


Date	% Change
January 1, 2025		(6.4	)
June 1, 2025		16.4
January 1, 2026		(1.1	)
May 1, 2026		24.1

Market-based Rates

Our operating revenues from sales to member distribution cooperatives - market-based rates for the three months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026		2025
	(in thousands)
Member distribution cooperatives:
Market-based rates:
Energy revenues	$	79,073	$	23,804
Demand revenues		12,751		3,501
Total Market-based rates revenues	$	91,824	$	27,305

Energy sales to:	(in MWh)
Member distribution cooperatives - market-based rates		705,574		388,567

For the three months ended March 31, 2026, total market-based rates revenues increased $64.5 million, or 236.3%, as compared to the same period in 2025, due to load growth related to increased member distribution cooperatives sales 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 months ended March 31, 2026 and 2025:


	Three Months Ended March 31,
	2026			2025
	(in thousands)
Fuel	$	165,546		$	93,729
Purchased power		250,755			157,622
Transmission		61,039			60,290
Deferred energy		(148,585	)		(66,814	)
Operations and maintenance		24,781			24,260
Administrative and general		14,952			13,954
Depreciation and amortization		17,441			17,708
Amortization of regulatory asset/(liability), net		1,176			(158	)
Accretion of asset retirement obligations		1,792			1,729
Taxes, other than income taxes		2,294			2,308
Total operating expenses	$	391,191		$	304,628

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 $86.6 million, or 28.4%, for the three months ended March 31, 2026, as compared to the same period in 2025, primarily as a result of increases in purchased power expense and fuel expense, partially offset by the decrease in deferred energy expense.

•

Purchased power expense, which includes the cost of purchased energy and capacity, increased $93.1 million, or 59.1%.

•

Purchased energy costs increased $94.6 million, or 66.0%, due to increases in the average cost and volume of purchased energy.

•

The average cost of purchased energy increased 55.4%.

•

The volume of purchased energy increased 6.8% primarily due to the increase in purchased energy in MWh for market-based rates sales.

•

Purchased capacity costs decreased $1.5 million, or 10.2%. Purchased capacity costs related to load served under the formula rate decreased $7.0 million, offset by the $5.5 million increase in purchased capacity costs related to load served under market-based rates.

•

Fuel expense increased $71.8 million, or 76.6%. The average cost of fuel increased 58.9% and generation from our owned facilities increased 11.2%.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, decreased $81.8 million. For the three months ended March 31, 2026, we under-collected $148.6 million primarily as a result of the periods of extreme cold weather in January and February of 2026. 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 2025 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, which is included in other interest. The major components of interest charges, net for the three months ended March 31, 2026 and 2025, were as follows:


	Three Months Ended March 31,
	2026			2025
	(in thousands)
Interest on long-term debt	$	(13,713	)	$	(10,977	)
Interest on revolving credit facility		(296	)		(1,137	)
Other interest		(608	)		(1,077	)
Total interest charges		(14,617	)		(13,191	)
Allowance for borrowed funds used during construction		1,097			713
Interest charges, net	$	(13,520	)	$	(12,478	)

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 relatively flat for the three months ended March 31, 2026, as compared to the same period in 2025. For both 2026 and 2025, our board of directors approved that an additional equity contribution of $27.5 million would be collected ratably through rates charged to our member distribution cooperatives. Also, in the fourth quarter of 2025, our board of directors approved an additional equity contribution of $11.0 million for a total of $38.5 million. For the three months ended March 31, 2026 and 2025, we recorded an additional equity contribution of $6.9 million.

Financial Condition

The principal changes in our financial condition from December 31, 2025 to March 31, 2026 were caused by the change in deferred energy, increases in revolving credit facility and fuel, materials, and supplies, partially offset by the decrease in accounts receivable–members.

•

Deferred energy changed $148.6 million due to the under-collection of our energy costs in 2026. Deferred energy changed from an over-collection of $59.0 million as of December 31, 2025, to an under-collection of $89.6 million as of March 31, 2026.

•

Revolving credit facility increased $50.0 million due to borrowings under this facility.

•

Fuel, materials, and supplies increased $42.6 million primarily due to the $33.7 million increase in RGGI CO2 allowances, the $5.2 million increase in renewable energy credits, and the $3.0 million increase in coal inventory.

•

Accounts receivable–members decreased $41.8 million primarily due to the $34.1 million decrease in wholesale power invoices for March 2026, as compared to December 2025, and the $7.4 million decrease in member distribution cooperatives extended payment balances, in accordance with the member power bill payment plan.

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 three months of 2026, our operating activities used cash flows of $75.7 million and for the first three months of 2025, our operating activities provided cash flows of $51.8 million.

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. The $400 million in aggregate commitments under this credit agreement mature on December 7, 2028, unless earlier terminated in accordance with the agreement. As of March 31, 2026, we had outstanding under this facility $50.0 million in borrowings. As of December 31, 2025, we did not have any borrowings outstanding under this facility. As of March 31, 2026 and December 31, 2025, we did not have any letters of credit outstanding under this 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, expansion, or improvement of our owned generating and transmission facilities. We continue to evaluate the issuance of additional long-term indebtedness to fund capital expenditures related to our existing generating and transmission facilities. Additionally, we are evaluating the need to construct new or expand existing 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 March 31, 2026, had a balance of $333.3 million. Our future contingent obligations primarily relate to power purchase and natural gas contracts, 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, asset retirement 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 first quarter of 2026.

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 the 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 the 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 2025 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 March 31, 2026, 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 2025 Annual Report on Form 10-K.

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: May 12, 2026		/s/ BRYAN S. ROGERS
		Bryan S. Rogers
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

OLD DOMINION ELECTRIC COOPERATIVE 10-Q