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, 2023


☐	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

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States

LIBOR		London Interbank Offered Rate

Louisa		Louisa Power Station

Marsh Run		Marsh Run Power Station

MMBTU		One Million British Thermal Units

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

SOFR		Secured Overnight Financing Rate

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, 2023 (unaudited) and December 31, 2022		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three and Nine Months Ended September 30, 2023 and 2022		5

Condensed Consolidated Statements of Cash Flows (unaudited) – Nine Months Ended September 30, 2023 and 2022		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		23

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		25

Item 6. Exhibits		26

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS


	September 30, 2023			December 31, 2022
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,562,798		$	2,549,435
Less accumulated depreciation		(1,164,746	)		(1,116,531	)
Net Property, plant, and equipment		1,398,052			1,432,904
Nuclear fuel, at amortized cost		11,278			19,155
Construction work in progress		78,449			56,075
Net Electric Plant		1,487,779			1,508,134
Investments:
Nuclear decommissioning trust		236,771			225,263
Unrestricted investments and other		2,539			2,437
Total Investments		239,310			227,700
Current Assets:
Cash and cash equivalents		77,175			15,213
Accounts receivable		19,489			36,573
Accounts receivable–members		98,528			111,838
Fuel, materials, and supplies		131,875			100,964
Deferred energy		—			83,836
Prepayments and other		14,098			19,391
Total Current Assets		341,165			367,815
Deferred Charges and Other Assets:
Regulatory assets		49,076			37,249
Other assets		49,076			64,081
Total Deferred Charges and Other Assets		98,152			101,330
Total Assets	$	2,166,406		$	2,204,979
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	485,613		$	476,082
Non-controlling interest		6,538			6,296
Total Patronage capital and Non-controlling interest		492,151			482,378
Long-term debt		972,483			972,167
Revolving credit facility		90,000			50,000
Total Long-term debt and Revolving credit facility		1,062,483			1,022,167
Total Capitalization		1,554,634			1,504,545
Current Liabilities:
Long-term debt due within one year		49,041			49,041
Accounts payable		83,615			167,601
Accounts payable–members		102,120			108,729
Accrued expenses		21,502			5,967
Deferred energy		2,721			—
Total Current Liabilities		258,999			331,338
Deferred Credits and Other Liabilities:
Asset retirement obligations		195,227			190,670
Regulatory liabilities		119,876			161,953
Other liabilities		37,670			16,473
Total Deferred Credits and Other Liabilities		352,773			369,096
Total Capitalization and Liabilities	$	2,166,406		$	2,204,979

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,
	2023			2022			2023			2022
	(in thousands)
Operating Revenues	$	294,561		$	297,562		$	824,614		$	724,396
Operating Expenses:
Fuel		47,502			59,436			148,335			131,088
Purchased power		89,222			139,655			246,492			339,980
Transmission		44,442			40,131			129,030			110,208
Deferred energy		38,865			(12,370	)		86,557			(61,206	)
Operations and maintenance		25,709			23,530			67,196			65,861
Administrative and general		10,879			10,892			32,121			31,607
Depreciation and amortization		17,439			17,295			52,104			51,906
Amortization of regulatory asset/(liability), net		634			(839	)		1,121			(1,273	)
Accretion of asset retirement obligations		1,520			1,469			4,557			4,404
Taxes, other than income taxes		2,244			2,168			6,837			6,765
Total Operating Expenses		278,456			281,367			774,350			679,340
Operating Margin		16,105			16,195			50,264			45,056
Other income (expense), net		7			(25	)		(200	)		2,003
Investment income		2,530			944			6,437			2,708
Interest charges, net		(15,426	)		(14,009	)		(46,634	)		(40,963	)
Income taxes		(15	)		(54	)		(94	)		(103	)
Net Margin including Non-controlling interest		3,201			3,051			9,773			8,701
Non-controlling interest		(45	)		(185	)		(242	)		(325	)
Net Margin attributable to ODEC		3,156			2,866			9,531			8,376
Patronage Capital - Beginning of Period		482,457			470,287			476,082			464,777
Patronage Capital - End of Period	$	485,613		$	473,153		$	485,613		$	473,153

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,
	2023			2022
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	9,773		$	8,701
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		52,104			51,906
Other non-cash charges		12,750			12,118
Change in current assets		4,776			(41,193	)
Change in deferred energy		86,557			(61,206	)
Change in current liabilities		(79,003	)		24,602
Change in regulatory assets and liabilities		(61,337	)		84,884
Change in deferred charges and other assets and deferred credits and other liabilities		36,192			(51,759	)
Net Cash Provided by Operating Activities		61,812			28,053
Investing Activities:
Purchases of held to maturity securities		—			(80,012	)
Increase in other investments		(4,167	)		(2,030	)
Electric plant additions		(35,683	)		(24,587	)
Net Cash Used for Investing Activities		(39,850	)		(106,629	)
Financing Activities:
Draws on revolving credit facility		318,000			20,000
Repayments on revolving credit facility		(278,000	)		(20,000	)
Net Cash Provided by Financing Activities		40,000			—
Net Change in Cash and Cash Equivalents		61,962			(78,576	)
Cash and Cash Equivalents - Beginning of Period		15,213			107,852
Cash and Cash Equivalents - End of Period	$	77,175		$	29,276

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, 2023, our consolidated results of operations for the three and nine months ended September 30, 2023 and 2022, and cash flows for the nine months ended September 30, 2023 and 2022. The consolidated results of operations for the three and nine months ended September 30, 2023, 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 2022 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 $6.5 million and $12.7 million as of September 30, 2023 and December 31, 2022, 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.

We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948 and currently are exempt from federal income taxation under IRC Section 501(c)(12). In order to maintain our tax-exempt status, we must receive at least 85% of our income from our members on an annual basis. We maintained our tax-exempt status as of September 30, 2023.

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, 2023 and December 31, 2022:


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	September 30,		Assets		Inputs		Inputs
	2023		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	72,564	$	72,564	$	—	$	—
Nuclear decommissioning trust - net asset value (1)(2)		164,207		—		—		—
Unrestricted investments and other (3)		381		—		381		—
Derivatives - gas and power (4)		2,657		—		2,657		—
Total financial assets	$	239,809	$	72,564	$	3,038	$	—

Derivatives - gas and power (4)	$	35,190	$	24,157	$	6,359	$	4,674
Total financial liabilities	$	35,190	$	24,157	$	6,359	$	4,674


			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs
	2022		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	73,945	$	73,945	$	—	$	—
Nuclear decommissioning trust - net asset value (1)(2)		151,318		—		—		—
Unrestricted investments and other (3)		279		—		279		—
Derivatives - gas and power (4)		59,902		27,839		20,773		11,290
Total financial assets	$	285,444	$	101,784	$	21,052	$	11,290

Derivatives - gas and power (4)	$	8,721	$	—	$	8,721	$	—
Total financial liabilities	$	8,721	$	—	$	8,721	$	—

(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 2022 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 2022 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	2023		2022
Natural gas	MMBTU		112,840,000		91,770,000
Purchased power - financial transmission rights	MWh		11,224,650		8,450,239

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	2023		2022
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	2,657	$	48,612
Financial transmission rights	Other assets		—		11,290
Total Derivatives in an asset position		$	2,657	$	59,902

Derivatives in a liability position:
Natural gas futures contracts	Other liabilities	$	30,516	$	8,721
Financial transmission rights	Other liabilities		4,674		—
Total Derivatives in a liability position		$	35,190	$	8,721

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, 2023 and 2022


	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,
	2023			2022			2023			2022		2023			2022
	(in thousands)						(in thousands)
Natural gas futures contracts	$	(29,360	)	$	115,535	Fuel	$	(14,351	)	$	49,789	$	(56,488	)	$	103,419
Purchased power		(4,674	)		18,293	Purchased power		5,188			9,408		(12,287	)		15,236
Total	$	(34,034	)	$	133,828		$	(9,163	)	$	59,197	$	(68,775	)	$	118,655

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, 2023 and December 31, 2022:


			Gross		Gross
			Unrealized		Unrealized			Fair		Carrying
Description	Cost		Gains		Losses			Value		Value
	(in thousands)
September 30, 2023
Nuclear decommissioning trust (1)
Debt securities	$	89,079	$	—	$	(16,607	)	$	72,472	$	72,472
Equity securities		95,811		75,575		(7,179	)		164,207		164,207
Cash and other		92		—		—			92		92
Total Nuclear decommissioning trust	$	184,982	$	75,575	$	(23,786	)	$	236,771	$	236,771

Other
Equity securities	$	330	$	51	$	—		$	381	$	381
Non-marketable equity investments		2,158		2,308		—			4,466		2,158
Total Other	$	2,488	$	2,359	$	—		$	4,847	$	2,539
										$	239,310
December 31, 2022
Nuclear decommissioning trust (1)
Debt securities	$	86,770	$	—	$	(13,083	)	$	73,687	$	73,687
Equity securities		93,878		64,139		(6,699	)		151,318		151,318
Cash and other		258		—		—			258		258
Total Nuclear decommissioning trust	$	180,906	$	64,139	$	(19,782	)	$	225,263	$	225,263

Other
Equity securities	$	238	$	41	$	—		$	279	$	279
Non-marketable equity investments		2,158		2,182		—			4,340		2,158
Total Other	$	2,396	$	2,223	$	—		$	4,619	$	2,437
										$	227,700

(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 2022 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, 2023, were as follows:



Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Other (1)	$	—	$	—	$	72,472	$	—	$	72,472
Total	$	—	$	—	$	72,472	$	—	$	72,472

(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 $400 million 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. Commitments under this syndicated credit agreement extend through February 28, 2025. The agreement was amended in June 2023 to replace LIBOR with SOFR as the benchmark index for calculating interest payable on borrowings under the agreement. As of September 30, 2023 and December 31, 2022, we had outstanding under this facility $90.0 million and $50.0 million in borrowings, respectively. As of September 30, 2023 and December 31, 2022, we had a $0.5 million letter of credit outstanding under this facility.

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, 2023 and 2022, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)
Operating revenues:
Member distribution cooperatives:
Formula rate:
Energy revenues	$	155,828	$	171,014	$	437,988	$	377,656
Renewable energy credits		96		90		269		181
Demand revenues		110,922		102,501		323,566		301,484
Total Formula rate revenues		266,846		273,605		761,823		679,321
Market-based rates:
Energy revenues		5,006		—		12,881		—
Demand revenues		750		—		1,850		—
Total Market-based rates revenues		5,756		—		14,731		—

Total Member distribution cooperatives revenues		272,602		273,605		776,554		679,321

Non-members:
Energy revenues (1)		2,764		11,977		26,216		33,095
Renewable energy credits		19,195		11,980		21,844		11,980
Total Non-members revenues		21,959		23,957		48,060		45,075

Total Operating revenues	$	294,561	$	297,562	$	824,614	$	724,396

(1)

Includes TEC sales to non-members from second quarter 2022 through first quarter 2023. TEC’s sales to non-members were $8.9 million for the nine months ended September 30, 2023. TEC's sales to non-members were $11.3 million and $20.2 million for the three and nine months ended September 30, 2022, respectively.

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, 2023, there have been no significant changes in our critical accounting policies as disclosed in our 2022 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, 2023, as compared to the same periods in 2022, were primarily impacted by the changes to our total energy rate charged to our member distribution cooperatives - formula rate, the over-collection of energy costs, the decrease in purchased power expense, and changes in fuel expense.

•

Total revenues from sales to our member distribution cooperatives were relatively flat for the three months ended September 30, 2023. Total revenues from sales to our member distribution cooperatives increased 14.3% for the nine months ended September 30, 2023, primarily due to the increase in formula rate energy revenues. Formula rate energy revenues increased primarily due to the increases implemented to our total energy rate in May and July of 2022, partially offset by the decreases to our total energy rate in 2023, and the 6.0% decrease in energy sales in MWh to our member distribution cooperatives - formula rate. The weather in 2023 was milder as compared to 2022 and contributed to the decrease in energy sales in MWh.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, increased $51.2 million and $147.8 million, respectively, as a result of changes implemented to our total energy rate. For the three and nine months ended September 30, 2023, we over-collected $38.9 million and $86.6 million, respectively. For the three and nine months ended September 30, 2022, we under-collected $12.4 million and $61.2 million, respectively. Our deferred energy balance was an over-collection of $2.7 million at September 30, 2023 and an under-collection of $83.8 million at December 31, 2022.

•

Purchased power expense, which includes the cost of purchased energy and capacity, decreased 36.1% and 27.5%, respectively, primarily due to the decrease in purchased energy costs. Purchased energy costs decreased 37.4% for the three months ended September 30, 2023, due to the 52.0% decrease in the average cost of purchased energy, partially offset by the 30.5% increase in the volume of purchased energy. Purchased energy costs decreased 27.7% for the nine months ended September 30, 2023, due to the 30.3% decrease in the average cost of purchased energy, slightly offset by the 3.7% increase in the volume of purchased energy.

•

Fuel expense decreased 20.1% for the three months ended September 30, 2023, due to the 12.4% decrease in the average cost of fuel and the 8.8% decrease in generation from our owned facilities. The average cost of fuel includes realized losses on our natural gas futures contracts of $14.4 million in 2023 and realized gains on our natural gas futures contracts of $49.8 million in 2022. Fuel expense increased 13.2% for the nine months ended September 30, 2023, due to the 9.4% increase in the average cost of fuel and the 3.5% increase in generation from our owned facilities. The average cost of fuel includes realized losses on our natural gas futures contracts of $56.5 million in 2023 and realized gains on our natural gas futures contracts of $103.4 million in 2022.

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 2022 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 first election to utilize market-based rates occurred in the first quarter of 2023.

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, 2023, and to reduce revenues for the nine months ended September 30, 2023, and for the three and nine months ended September 30, 2022.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2023			2022		2023		2022
	(in thousands)
Margin Stabilization adjustment	$	(1,844	)	$	672	$	2,293	$	8,027

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 2022 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, 2023, were as follows:


	Three Months Ended September 30,							Nine Months Ended September 30,
	2023		2022		Change			2023		2022		Change
Heating degree days		—		—		—	%		1,610		2,248		(28.4	)%
Cooling degree days		928		957		(3.0	)		1,062		1,326		(19.9	)

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, 2023 and 2022, were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
	(in MWh and percentages)
Generated:
Wildcat Point	1,305,708	37.6	%	1,481,533	45.0	%	3,466,453	35.5	%	3,172,130	33.6	%
North Anna	423,993	12.2		360,280	10.9		1,405,412	14.4		1,227,745	13.0
Clover	63,310	1.8		87,677	2.7		98,799	1.0		258,165	2.7
Louisa	61,687	1.8		67,552	2.1		152,266	1.6		163,970	1.8
Marsh Run	57,890	1.7		100,398	3.0		128,856	1.3		253,832	2.7
Distributed Generation	1,302	—		1,041	—		2,355	0.0		1,674	—
Total Generated	1,913,890	55.1		2,098,481	63.7		5,254,141	53.8		5,077,516	53.8
Purchased:
Other than renewable:
Long-term and short-term	766,071	22.1		530,997	16.1		2,652,358	27.1		1,920,946	20.4
Spot market	682,471	19.6		554,367	16.8		1,368,560	14.0		1,922,929	20.4
Total Other than renewable	1,448,542	41.7		1,085,364	32.9		4,020,918	41.1		3,843,875	40.8
Renewable (1)	111,450	3.2		110,268	3.4		498,142	5.1		512,081	5.4
Total Purchased	1,559,992	44.9		1,195,632	36.3		4,519,060	46.2		4,355,956	46.2
Total Available Energy	3,473,882	100.0	%	3,294,113	100.0	%	9,773,201	100.0	%	9,433,472	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 2022 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, 2023 and 2022, was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Wildcat Point		99.2	%		98.4	%		91.6	%		90.3	%
North Anna		87.7			75.1			95.8			84.6
Clover		93.2			97.4			70.9			74.3
Louisa		99.9			100.0			98.6			95.8
Marsh Run		99.8			99.9			94.5			98.3

Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the three and nine months ended September 30, 2023 and 2022, as a percentage of maximum dependable capacity rating of the facilities, was as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
Wildcat Point		60.4	%		68.6	%		54.0	%		49.4	%
North Anna		87.5			74.3			97.7			85.4
Clover		6.9			9.6			3.6			9.3

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, 2023 and 2022, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)
Operating revenues:
Member distribution cooperatives:
Formula rate	$	266,846	$	273,605	$	761,823	$	679,321
Market-based rates		5,756		—		14,731		—
Total Member distribution cooperatives		272,602		273,605		776,554		679,321

Non-members (1)		21,959		23,957		48,060		45,075
Total Operating revenues	$	294,561	$	297,562	$	824,614	$	724,396


Energy sales to:	(in MWh)
Member distribution cooperatives - formula rate		3,178,754	3,119,017	8,400,761	8,937,698
Member distribution cooperatives - market-based rates		138,839	—	368,720	—
Non-members		124,356	157,172	932,951	444,291
Total Energy sales		3,441,949	3,276,189	9,702,432	9,381,989

(1)

Includes TEC sales to non-members from second quarter 2022 through first quarter 2023. TEC's sales to non-members were $8.9 million for the nine months ended September 30, 2023. TEC's sales to non-members were $11.3 million and $20.2 million for the three and nine months ended September 30, 2022, respectively.

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, 2023 and 2022, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
	(in thousands)
Member distribution cooperatives:
Formula rate:
Energy revenues	$	155,828	$	171,014	$	437,988	$	377,656
Renewable energy credits		96		90		269		181
Demand revenues		110,922		102,501		323,566		301,484
Total Formula rate revenues	$	266,846	$	273,605	$	761,823	$	679,321

Energy sales to:	(in MWh)
Member distribution cooperatives - formula rate		3,178,754		3,119,017		8,400,761		8,937,698

Average cost to member distribution cooperatives:	(per MWh)
Formula rate energy cost	$	49.02	$	54.83	$	52.14	$	42.25
Formula rate total cost	$	83.95	$	87.72	$	90.68	$	76.01

For the three months ended September 30, 2023, total formula rate revenues decreased $6.8 million, or 2.5%, as compared to the same period in 2022. Formula rate energy revenues decreased $15.2 million, or 8.9%, due to the changes in our total energy rate. The decrease was slightly offset by the 1.9% increase in energy sales in MWh to our member distribution cooperatives - formula rate. Formula rate demand revenues increased $8.4 million, or 8.2%, primarily due to changes in PJM charges for network transmission services.

For the nine months ended September 30, 2023, total formula rate revenues increased $82.5 million, or 12.1%, as compared to the same period in 2022. Formula rate energy revenues increased $60.3 million, or 16.0%, due to the changes in our total energy rate. The increase was partially offset by the 6.0% decrease in energy sales in MWh to our member distribution cooperatives - formula rate. Formula rate demand revenues increased $22.1 million, or 7.3%, primarily due to changes in PJM charges for network transmission services.

The following table summarizes the changes to our total energy rate since 2022, which were implemented to address the differences in our realized as well as projected energy costs:


Date	% Change
January 1, 2022		20.3
May 1, 2022		6.7
July 1, 2022		47.7
January 1, 2023		(1.5	)
August 1, 2023		(14.8	)

Market-based Rates

Our operating revenues from sales to member distribution cooperatives - market-based rates for the three and nine months ended September 30, 2023 and 2022, were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2023		2022		2023		2022
Member distribution cooperatives:	(in thousands)
Market-based rates:
Energy revenues	$	5,006	$	—	$	12,881	$	—
Demand revenues		750		—		1,850		—
Total Market-based rates revenues	$	5,756	$	—	$	14,731	$	—

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

Operating Expenses

The following is a summary of the components of our operating expenses for the three and nine months ended September 30, 2023 and 2022:


	Three Months Ended September 30,					Nine Months Ended September 30,
	2023		2022			2023		2022
	(in thousands)
Fuel	$	47,502	$	59,436		$	148,335	$	131,088
Purchased power		89,222		139,655			246,492		339,980
Transmission		44,442		40,131			129,030		110,208
Deferred energy		38,865		(12,370	)		86,557		(61,206	)
Operations and maintenance		25,709		23,530			67,196		65,861
Administrative and general		10,879		10,892			32,121		31,607
Depreciation and amortization		17,439		17,295			52,104		51,906
Amortization of regulatory asset/(liability), net		634		(839	)		1,121		(1,273	)
Accretion of asset retirement obligations		1,520		1,469			4,557		4,404
Taxes, other than income taxes		2,244		2,168			6,837		6,765
Total operating expenses	$	278,456	$	281,367		$	774,350	$	679,340

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 decreased $2.9 million, or 1.0%, for the three months ended September 30, 2023, and increased $95.0 million, or 14.0%, for the nine months ended September 30, 2023, as compared to the same periods in 2022. Operating expenses decreased for the three months ended September 30, 2023, primarily as a result of the decrease in purchased power expense and fuel expense, substantially offset by the increase in deferred energy expense. Operating

expenses for the nine months ended September 30, 2023, increased primarily as a result of the increase in deferred energy expense and fuel expense, partially offset by the decrease in purchased power expense.

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Deferred energy expense, which represents the difference between energy revenues and energy expenses, increased $51.2 million and $147.8 million, respectively, as a result of changes implemented to our total energy rate. For the three and nine months ended September 30, 2023, we over-collected $38.9 million and $86.6 million, respectively. For the three and nine months ended September 30, 2022, we under-collected $12.4 million and $61.2 million, respectively. For further discussion on deferred energy, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies—Deferred Energy” in Item 7 in our 2022 Annual Report on Form 10-K.

•

Purchased power expense, which includes the cost of purchased energy and capacity, decreased $50.4 million, or 36.1%, and $93.5 million, or 27.5%, for the three and nine months ended September 30, 2023, respectively, primarily due to the decrease in purchased energy costs. Purchased energy costs decreased $51.2 million, or 37.4%, for the three months ended September 30, 2023, due to the 52.0% decrease in the average cost of purchased energy, partially offset by the 30.5% increase in the volume of purchased energy. Purchased energy costs decreased $90.9 million, or 27.7%, for the nine months ended September 30, 2023, due to the 30.3% decrease in the average cost of purchased energy, slightly offset by the 3.7% increase in the volume of purchased energy.

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Fuel expense decreased $11.9 million, or 20.1%, for the three months ended September 30, 2023, due to the 12.4% decrease in the average cost of fuel and the 8.8% decrease in generation from our owned facilities. The average cost of fuel includes realized losses on our natural gas futures contracts of $14.4 million in 2023 and realized gains on our natural gas futures contracts of $49.8 million in 2022. Fuel expense increased $17.2 million, or 13.2%, for the nine months ended September 30, 2023, due to the 9.4% increase in the average cost of fuel and the 3.5% increase in generation from our owned facilities. The average cost of fuel includes realized losses on our natural gas futures contracts of $56.5 million in 2023 and realized gains on our natural gas futures contracts of $103.4 million in 2022.

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, 2023 and 2022, were as follows:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2023			2022			2023			2022
	(in thousands)
Interest on long-term debt	$	(12,311	)	$	(13,347	)	$	(36,919	)	$	(40,028	)
Interest on revolving credit facility		(1,806	)		(84	)		(5,680	)		(265	)
Other interest		(1,661	)		(895	)		(5,054	)		(1,584	)
Total interest charges		(15,778	)		(14,326	)		(47,653	)		(41,877	)
Allowance for borrowed funds used during construction		352			317			1,019			914
Interest charges, net	$	(15,426	)	$	(14,009	)	$	(46,634	)	$	(40,963	)

Interest on revolving credit facility increased $1.7 million and $5.4 million for the three and nine months ended September 30, 2023, respectively, as compared to the same periods in 2022, due to the increase in borrowings under this facility. Other interest increased $0.8 million and $3.5 million for the three and nine months ended September 30, 2023, respectively, as compared to the same periods in 2022, primarily due to interest paid on prepayment balances. We maintain a program which allows our member distribution cooperatives to prepay their monthly power bills. Under this program, we pay interest on prepayment balances at a blended investment and short-term borrowing rate.

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, increased 10.1% and 13.8%, for the three and nine months ended September 30, 2023, respectively, as compared to the same periods in 2022, due to the increase in total interest charges.

Financial Condition

The principal changes in our financial condition from December 31, 2022 to September 30, 2023, were caused by changes in deferred energy, decreases in accounts payable and regulatory liabilities, and increases in revolving credit facility; fuel, materials, and supplies; and other liabilities.

•

Deferred energy changed $86.6 million due to the over-collection of our energy costs in 2023. Our deferred energy balance was an over-collection of $2.7 million at September 30, 2023 and an under-collection of $83.8 million at December 31, 2022.

•

Accounts payable decreased $84.0 million primarily due to the decrease in purchased power and natural gas payables.

•

Regulatory liabilities decreased $42.1 million primarily due to the regulatory liability related to derivatives partially offset by the change in the unrealized gain on the North Anna nuclear decommissioning fund.

•

Revolving credit facility increased $40.0 million due to outstanding borrowings under this facility to fund short-term working capital needs.

•

Fuel, materials, and supplies increased $30.9 million primarily due to the $23.8 million increase in coal inventory and the $5.6 million increase in diesel fuel inventory.

•

Other liabilities increased $21.2 million primarily due to the decrease in the fair value of our natural gas hedges.

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 2023 and 2022, our operating activities provided cash flows of $61.8 million and $28.1 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 currently have no plans to construct major new generating or transmission facilities; however, we are evaluating the issuance of additional long-term indebtedness in the near term to fund capital expenditures related to our existing generating and transmission facilities. 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, 2023, had a balance of $236.8 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 2023.

ITEM 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the Interim 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 Interim 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

Our member distribution cooperatives serve a variety of major industries, including data centers. Both the number and size of data centers that are being considered for development and construction in the service territories of our member distribution cooperatives may increase substantially over the next several years, thereby materially increasing the aggregate power requirements of our member distribution cooperatives. Our need to serve the power requirements of these data centers, which could be thousands of megawatts over the next decade, has the potential to create several material risks.

We have a wholesale power contract with each of our member distribution cooperatives that obligates us to sell and deliver to the member distribution cooperative, and obligates that member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so. 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. While the energy required to serve the power requirements of data centers would be supplied by resources subject to dispatch by PJM, we would be financially responsible to PJM for the payment of purchases of energy, capacity, and other ancillary services associated with these requirements.

The increased power purchases arising from new data centers in our member distribution cooperatives’ service territories likely would increase the collateral we are required to post with PJM. These collateral requirements could result in the need to provide an increased amount of credit support in the form of cash or standby letters of credit within a short amount of time based on market conditions. Our ability to access additional credit may be limited and our liquidity may be materially impacted in these circumstances. Constraints on our collateral resources could cause it to become more expensive for us to do business with others or risk a potential downgrade by a rating agency that could increase future borrowing costs.

These adverse consequences also could arise if a data center fails to pay its power bill to one of our member distribution cooperatives. Any security provided by a data center may not be sufficient to permit our member distribution cooperative to meet its payment obligations under the wholesale power contract. Depending on the amount of the non-payment, our member distribution cooperative may find it difficult to meet its financial obligations to us and others in a timely manner. As a result, we could be subject to rating downgrades, increased collateral requirements, and liquidity impairments for this reason as well.

State laws relating to the provision of electric services to large commercial customers may result in other utilities supplying the power requirements of these new data centers, even if our member distribution cooperatives provide other distribution services to them. Under Virginia law, our member distribution cooperatives generally are the default providers of power to customers in their respective certificated service territories, but an exception exists for some large retail customers to select their power supplier. This exception may apply to the new data centers being considered in Virginia. Delaware and Maryland grant all retail customers the right to choose their power supplier. In all cases, the retail customer controls the exercise of the right to obtain power supply from a non-incumbent power supplier, with some limitations.

We continue to evaluate the potential impacts of the development, construction and operation of new data centers in our member distribution cooperatives’ service territories and will continue to evaluate potential mitigants to these risks.

Still, we cannot predict whether the data centers under consideration will ever commence operations, the size of the power requirements of those that do become operational, whether they will seek to be served by a power supplier other than our member distribution cooperatives, and their ability or willingness to pay their financial obligations in a timely manner. For these and other reasons, there can be no assurance that these developments will not have a material adverse effect on our business, results of operations, financial condition, or cash flows.

In addition to the above risk and other information set forth in this report, carefully consider the risk factors disclosed in Part I, Item 1A “Risk Factors” in our 2022 Annual Report on Form 10-K, which could affect our business, results of operations, financial condition, and cash flows. There are other risks and uncertainties that may also impair our business operations. These 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, 2023, 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 2022 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 Document
101.CAL		Inline XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		Inline XBRL Taxonomy Extension Label Linkbase Document
101.PRE		Inline XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		Inline XBRL Taxonomy Extension Definition Linkbase Document
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 7, 2023		/s/ BRYAN S. ROGERS
		Bryan S. Rogers
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)