OLD DOMINION ELECTRIC COOPERATIVE - FORM 10-Q

OLD DOMINION ELECTRIC COOPERATIVE - FORM 10-Q - May 11, 2021

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OLD DOMINION ELECTRIC COOPERATIVE Reports

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EX-32.2 - EX-32.2 - OLD DOMINION ELECTRIC COOPERATIVE	cik0000885568-ex322_7.htm
EX-32.1 - EX-32.1 - OLD DOMINION ELECTRIC COOPERATIVE	cik0000885568-ex321_6.htm
EX-31.2 - EX-31.2 - OLD DOMINION ELECTRIC COOPERATIVE	cik0000885568-ex312_8.htm
EX-31.1 - EX-31.1 - OLD DOMINION ELECTRIC COOPERATIVE	cik0000885568-ex311_9.htm

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, 2021

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

For the transition period from to

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)

VIRGINIA

23-7048405

(State or other jurisdiction of

incorporation or organization)

(I.R.S. employer

identification no.)

4201 Dominion Boulevard, Glen Allen, Virginia		23060
(Address of principal executive offices)		(Zip code)

(804) 747-0592

(Registrant’s telephone number, including area code)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ 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

ASU		Accounting Standards Update

Clover		Clover Power Station

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

GAAP		Accounting principles generally accepted in the United States

Louisa		Louisa Power Station

Marsh Run		Marsh Run Power Station

MWh		Megawatt hour(s)

North Anna		North Anna Nuclear Power Station

ODEC, We, Our, Us		Old Dominion Electric Cooperative

PJM		PJM Interconnection, LLC

RTO		Regional transmission organization

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, 2021 (unaudited) and December 31, 2020		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three Months Ended March 31, 2021 and 2020		5

Condensed Consolidated Statements of Cash Flows (unaudited) – Three Months Ended March 31, 2021 and 2020		6

Notes to Condensed Consolidated Financial Statements		7

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		14

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 6. Exhibits		25

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	March 31, 2021			December 31, 2020
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,537,293		$	2,536,395
Less accumulated depreciation		(1,001,287	)		(984,076	)
Net Property, plant, and equipment		1,536,006			1,552,319
Nuclear fuel, at amortized cost		14,722			17,321
Construction work in progress		42,694			38,810
Net Electric Plant		1,593,422			1,608,450
Investments:
Nuclear decommissioning trust		250,290			242,337
Unrestricted investments and other		2,317			2,311
Total Investments		252,607			244,648
Current Assets:
Cash and cash equivalents		55,232			9,288
Accounts receivable		13,342			16,909
Accounts receivable–members		47,113			79,813
Fuel, materials, and supplies		62,502			61,273
Prepayments and other		3,650			5,598
Total Current Assets		181,839			172,881
Deferred Charges and Other Assets:
Regulatory assets		26,192			31,131
Other assets		8,998			10,534
Total Deferred Charges and Other Assets		35,190			41,665
Total Assets	$	2,063,058		$	2,067,644
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	456,310		$	453,470
Non-controlling interest		5,848			5,853
Total Patronage capital and Non-controlling interest		462,158			459,323
Long-term debt		1,069,441			1,069,324
Total Capitalization		1,531,599			1,528,647
Current Liabilities:
Long-term debt due within one year		49,041			49,041
Accounts payable		57,595			61,044
Accounts payable–members		60,599			70,546
Accrued expenses		21,157			6,292
Deferred energy		7,171			23,112
Total Current Liabilities		195,563			210,035
Deferred Credits and Other Liabilities:
Asset retirement obligations		180,548			179,133
Regulatory liabilities		152,941			142,724
Other liabilities		2,407			7,105
Total Deferred Credits and Other Liabilities		335,896			328,962
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	2,063,058		$	2,067,644

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,
	2021			2020
	(in thousands)
Operating Revenues	$	191,117		$	208,746
Operating Expenses:
Fuel		39,754			42,578
Purchased power		70,992			92,890
Transmission		31,626			33,916
Deferred energy		(15,940	)		(25,135	)
Operations and maintenance		16,436			13,742
Administrative and general		10,880			11,856
Depreciation and amortization		17,676			17,522
Amortization of regulatory asset/(liability), net		2,487			(790	)
Accretion of asset retirement obligations		1,415			1,365
Taxes, other than income taxes		2,425			2,422
Total Operating Expenses		177,751			190,366
Operating Margin		13,366			18,380
Other income (expense), net		71			(57	)
Investment income		3,406			350
Interest charges, net		(14,010	)		(15,537	)
Income taxes		2			(3	)
Net Margin including Non-controlling interest		2,835			3,133
Non-controlling interest		5			(9	)
Net Margin attributable to ODEC		2,840			3,124
Patronage Capital - Beginning of Period		453,470			441,311
Patronage Capital - End of Period	$	456,310		$	444,435

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,
	2021			2020
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	2,835		$	3,133
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		17,676			17,522
Other non-cash charges		4,129			4,471
Change in current assets		36,986			37,332
Change in deferred energy		(15,940	)		(25,135	)
Change in current liabilities		2,981			53,259
Change in regulatory assets and liabilities		10,594			5,886
Change in deferred charges and other assets and deferred credits and other liabilities		(3,167	)		(3,690	)
Net Cash Provided by Operating Activities		56,094			92,778
Investing Activities:
Increase in other investments		(3,392	)		(78	)
Electric plant additions		(6,758	)		(47,516	)
Net Cash Used for Investing Activities		(10,150	)		(47,594	)
Financing Activities:
Debt issuance costs		—			(235	)
Draws on revolving credit facility		—			349,225
Repayments on revolving credit facility		—			(166,425	)
Net Cash Provided by Financing Activities		—			182,565
Net Change in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents		45,944			227,749
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - Beginning of Period		9,288			27,699
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - End of Period	$	55,232		$	255,448

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 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, 2021, our consolidated results of operations for the three months ended March 31, 2021 and 2020, and cash flows for the three months ended March 31, 2021 and 2020. The consolidated results of operations for the three months ended March 31, 2021, 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 2020 Annual Report on Form 10-K filed with the Securities and Exchange Commission.

The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and TEC. We are a not-for-profit wholesale power supply cooperative, incorporated under the laws of the Commonwealth of Virginia in 1948. 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 $5.8 million as of March 31, 2021 and December 31, 2020. 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.

The impact that the COVID-19 pandemic will have on our consolidated results of operations, financial condition, and cash flows is uncertain. We continue to actively manage our business to respond to this health crisis and will continue to evaluate the nature and extent of any impact.

2.	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 table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of March 31, 2021 and December 31, 2020:

			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	March 31,		Assets		Inputs		Inputs
	2021		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾	$	73,029	$	73,029	$	—	$	—
Nuclear decommissioning trust - net asset value ⁽¹⁾⁽²⁾		177,261		—		—		—
Unrestricted investments and other ⁽³⁾		172		—		172		—
Derivatives - gas and power ⁽⁴⁾		5,145		4,531		526		88
Total Financial Assets	$	255,607	$	77,560	$	698	$	88

Derivatives - gas and power ⁽⁴⁾	$	1,409	$	—	$	1,409	$	—
Total Financial Liabilities	$	1,409	$	—	$	1,409	$	—

			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs
	2020		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾	$	76,037	$	76,037	$	—	$	—
Nuclear decommissioning trust - net asset value ⁽¹⁾⁽²⁾		166,300		—		—		—
Unrestricted investments and other ⁽³⁾		166		—		166		—
Derivatives - gas and power ⁽⁴⁾		3,478		1,582		480		1,416
Total Financial Assets	$	245,981	$	77,619	$	646	$	1,416

Derivatives - gas and power ⁽⁴⁾	$	6,406	$	—	$	6,406	$	—
Total Financial Liabilities	$	6,406	$	—	$	6,406	$	—

⁽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 and call option premiums (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 2020 Annual Report on Form 10-K.

3.	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 2020 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	2021		2020
Natural gas	MMBTU		46,440,000		55,630,000
Purchased power - financial transmission rights	MWh		7,109,024		6,922,373

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	2021		2020
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	5,057	$	2,062
Financial transmission rights	Other assets		88		1,416
Total derivatives in an asset position		$	5,145	$	3,478

Derivatives in a liability position:
Natural gas futures contracts	Other liabilities	$	1,409	$	6,406
Total derivatives in a liability position		$	1,409	$	6,406

The Effect of Derivative Instruments on the Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Three Months Ended March 31, 2021 and 2020

							Amount of Gain
							(Loss) Reclassified
	Amount of Gain					Location of	from Regulatory
	(Loss) Recognized					Gain (Loss)	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,
	2021		2020				2021			2020
	(in thousands)						(in thousands)
Natural gas futures contracts	$	3,711	$	(19,521	)	Fuel	$	(4,365	)	$	(21,466	)
Purchased power		88		532		Purchased power		3,612			(3,585	)
Total	$	3,799	$	(18,989	)		$	(753	)	$	(25,051	)

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.

4.	Investments

Investments were as follows as of March 31, 2021 and December 31, 2020:

			Gross		Gross
			Unrealized		Unrealized		Fair		Carrying
Description	Cost		Gains		Losses		Value		Value
	(in thousands)
March 31, 2021
Nuclear decommissioning trust ⁽¹⁾
Debt securities	$	68,197	$	4,188	$	—	$	72,385	$	72,385
Equity securities		92,567		84,694		—		177,261		177,261
Cash and other		644		—		—		644		644
Total Nuclear Decommissioning Trust	$	161,408	$	88,882	$	—	$	250,290	$	250,290

Other
Equity securities	$	132	$	39	$	—	$	171	$	171
Non-marketable equity investments		2,146		2,372		—		4,518		2,146
Total Other	$	2,278	$	2,411	$	—	$	4,689	$	2,317
									$	252,607

December 31, 2020
Nuclear decommissioning trust ⁽¹⁾
Debt securities	$	66,727	$	7,493	$	—	$	74,220	$	74,220
Equity securities		89,472		76,828		—		166,300		166,300
Cash and other		1,817		—		—		1,817		1,817
Total Nuclear Decommissioning Trust	$	158,016	$	84,321	$	—	$	242,337	$	242,337

Other
Equity securities	$	132	$	34	$	—	$	166	$	166
Non-marketable equity investments		2,145		2,340		—		4,485		2,145
Total Other	$	2,277	$	2,374	$	—	$	4,651	$	2,311
									$	244,648

⁽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 2020 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, 2021, were as follows:


Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Other ⁽¹⁾	$	—	$	—	$	72,385	$	—	$	72,385
Total	$	—	$	—	$	72,385	$	—	$	72,385

⁽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. Commitments under this syndicated credit agreement extend until February 28, 2025. Available funding under this facility totals $500 million through March 3, 2022, and $400 million from March 4, 2022 through February 28, 2025. As of March 31, 2021 and December 31, 2020, we had no borrowings and had a $0.5 million letter of credit outstanding under this facility.

Cash and Cash Equivalents

For purposes of our Condensed Consolidated Statements of Cash Flows, we consider all unrestricted highly liquid debt instruments purchased with an original maturity of three months or less to be cash equivalents.

The following table provides a reconciliation of cash and cash equivalents and restricted cash and cash equivalents reported within our Condensed Consolidated Balance Sheets that sum to the total of the same amounts shown in our Condensed Consolidated Statements of Cash Flows:

	As of March 31,
	2021		2020
	(in thousands)
Cash and cash equivalents	$	55,232	$	231,128
Restricted cash and cash equivalents		—		24,320
Total	$	55,232	$	255,448

Restricted cash and cash equivalents related to funds held in escrow for payments related to the construction of Wildcat Point and in July 2020 the funds were released and paid to the contractors.

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.

We sell excess purchased and generated energy to PJM, TEC, or third parties. Sales to TEC consist of sales of excess energy that we do not need to meet the actual needs of our member distribution cooperatives. TEC’s sales to third parties are reflected as non-member revenues. For the three months ended March 31, 2021 and 2020, we had no sales to TEC and TEC had no sales to third parties.

Our operating revenues for the three months ended March 31, 2021 and 2020, were as follows:

	Three Months Ended March 31,
	2021		2020
	(in thousands)
Member distribution cooperatives
Sales to member distribution cooperatives, excluding renewable energy credit sales	$	184,734	$	204,165
Renewable energy credit sales to member distribution cooperatives		9		—
Total sales to member distribution cooperatives	$	184,743	$	204,165

Non-members
Sales to non-members, excluding renewable energy credit sales	$	6,191	$	4,477
Renewable energy credit sales to non-members		183		104
Total sales to non-members	$	6,374	$	4,581

Total operating revenues	$	191,117	$	208,746

6.	New Accounting Pronouncements

In March 2020, the FASB issued ASU 2020-04 Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. The guidance provides temporary optional expedients and exceptions related to contract modifications and hedge accounting to ease entities’ financial reporting burdens as the market transitions from the London Interbank Offered Rate and other interbank offered rates to alternative reference rates. The new guidance allows entities to elect not to apply certain modification accounting requirements, if certain criteria are met, to contracts affected by what the guidance calls reference rate reform. An entity that makes this election would consider changes in reference rates and other contract modifications related to reference rate reform to be events that do not require contract remeasurement at the modification date or reassessment of a previous accounting determination. The ASU notes that changes in contract terms that are made to effect the reference rate reform transition are considered related to the replacement of a reference rate if they are not the result of a business decision that is separate from or in addition to changes to the terms of a contract to effect that transition. The guidance is effective upon issuance and generally can be applied as of March 12, 2020 through December 31, 2022. We are continuing to evaluate the impact of this standard on our financial statements.

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; the impact of the COVID-19 pandemic on our business, financial condition, and future operations; changes in and compliance with environmental laws and regulations; general credit and capital market conditions; weather conditions; the cost 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, 2021, there have been no significant changes in our critical accounting policies as disclosed in our 2020 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, 2021, were primarily impacted by the decreases in our total energy rate, purchased power expense, and PJM’s economic dispatch of our generating facilities, and weather.

•

Total revenues from sales to our member distribution cooperatives decreased 9.5% for the three months ended March 31, 2021, as compared to the same period in 2020, as a result of the 8.2% and 10.8% decrease in energy revenues and demand revenues, respectively. The decrease in energy revenues was primarily due to the 15.9% decrease in the total energy rate for the three months ended March 31, 2021, partially offset by the 9.2% increase in energy sales in MWh to our member distribution cooperatives. The weather for the three months ended March 31, 2020 was mild and the weather for the three months ended March 31, 2021 was more typical weather and contributed to the increase in energy sales in MWh to our member distribution cooperatives. The decrease in demand revenues was primarily due to the decrease in capacity-related purchased power expense.

•

Generation from our owned facilities decreased 10.4%, primarily due to PJM’s economic dispatch of our generating facilities.

•

Purchased power expense, which includes the cost of purchased energy and capacity, decreased 23.6%, due to the decrease in purchased energy and capacity costs. Purchased energy costs decreased 16.9%, due to the 30.9% decrease in the average cost of purchased energy, partially offset by the 20.4% increase in the volume of purchased energy, primarily as a result of decreased generation from our owned facilities. Purchased capacity costs decreased 75.7% due to the decrease in costs to meet our PJM capacity obligation.

We believe our results for the three months ended March 31, 2021 were not materially impacted by the COVID-19 pandemic. We believe that other factors described above, such as decreases in our total energy rate, purchased power expense, and PJM’s economic dispatch of our generating facilities, and the impact of weather, were the primary drivers of our results for the three months ended March 31, 2021. We continue to closely monitor how the pandemic will affect our operations, results of operations, financial condition, and cash flows, and have taken certain actions as a result of the pandemic. See “Factors Affecting Results—COVID-19 Pandemic” below for a more detailed discussion.

Factors Affecting Results

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 for sales of energy and demand are determined by a formula rate accepted by FERC, which is 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.

Energy costs, which are primarily variable costs, such as natural gas, nuclear, and coal fuel costs, and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate (collectively referred to as the total energy rate). The base energy rate is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to zero. We can revise the energy adjustment rate during the year if it becomes apparent that the total energy rate is over-collecting or under-collecting our actual and anticipated energy costs. Any revision to the energy adjustment rate requires board approval and that the resulting change to the total energy rate is at least 2%.

Demand costs, which are primarily fixed costs, such as capacity costs under power purchase contracts with third parties, transmission costs, administrative and general expenses, depreciation expense, interest expense, margin requirement, and additional equity contributions approved by our board of directors, are recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. We collect our total demand costs through the following three separate rates:

•

transmission service rate – designed to collect transmission-related and distribution-related costs;

•

RTO capacity service rate – designed to collect capacity costs in PJM that PJM allocates to ODEC and all other PJM members; and

•

remaining owned capacity service rate – designed to collect all remaining demand costs not billed and/or recovered under the transmission service and RTO capacity service rates.

As stated above, 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 described below).

We may revise our budget at any time to the extent that our current budget does not accurately reflect our costs and expenses or estimates of our sales of power. Increases or decreases in our budget automatically amend the energy and/or the demand components of our formula rate, as necessary. If at any time our board of directors determines that the formula does not recover all of our costs and expenses or determines a change in cost allocation methodology among our member distribution cooperatives is appropriate, it may adopt a new formula to meet those costs and expenses, subject to any necessary regulatory review and approval. On June 26, 2020, we submitted an application to FERC to revise our formula rate for a change in cost allocation methodology of our remaining owned capacity service rate, to be effective January 1, 2021. On August 25, 2020, FERC issued an order accepting our filing with an effective date of January 1, 2021.

As detailed in the table below, we utilized Margin Stabilization to reduce revenues for the three months ended March 31, 2021 and 2020.

	Three Months Ended March 31,
	2021		2020
	(in thousands)
Margin Stabilization adjustment	$	8,754	$	635

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 of our 2020 Annual Report on Form 10-K.

COVID-19 Pandemic

Impact on Results of Operations and Financial Condition

For the three months ended March 31, 2021, we do not believe there was a material impact attributable to the COVID-19 pandemic on our financial condition, results of operations, or cash flows.

Our total revenues decreased $17.6 million, or 8.4%, as compared to the same period in the prior year. The decrease was primarily due to the 15.9% decrease in our total energy rate to our member distribution cooperatives, effective January 1, 2021, partially offset by more typical weather in the first quarter of 2021 as compared to the mild weather in the first quarter of 2020.

Any decline in our member distribution cooperatives’ power requirements related to the COVID-19 pandemic would result in a reduction of our spot market energy purchases, or excess energy which we would sell to PJM, TEC, or third parties. In addition, the majority of our member distribution cooperatives’ loads are residential, which may be a factor in limiting the impact of the pandemic on our results of operations.

The formula rate provides for the recovery of costs, margin requirement, and any additional equity contributions approved by our board of directors, from our member distribution cooperatives. See “—Formula Rate” above. We operate on a cost plus specified margin basis; therefore, our net margin is not a function of total revenues. Our margin requirement is equal to 20% of actual interest charges, plus additional equity contributions approved by our board of directors. 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. To date, our member distribution cooperatives’ ability to pay their invoices to us has not been impacted. However, our member distribution cooperatives’ ability to pay their invoices to us may be impacted by certain factors including high unemployment rates, government actions protecting customers from the disconnection of utilities, and increased commercial or industrial closures/bankruptcies. Under an existing program, our member distribution cooperatives have the option to prepay their invoices from us or to extend payment of their invoices for 60 days. As of March 31, 2021, prepayments totaled $51.8 million and extensions totaled $1.3 million.

We increased our cash and cash equivalents balance to $231.1 million as of March 31, 2020, by borrowing funds under our revolving credit facility due to uncertainties associated with the COVID-19 pandemic. As of March 31, 2021, we had no borrowings outstanding under our revolving credit facility and had a cash and cash equivalents balance of $55.2 million.

Workforce Considerations

ODEC is considered an essential service provider and due to the COVID-19 pandemic, we adjusted the schedules of our workforce for March through June 2020 at our owned generating facilities that we operate, specifically Wildcat Point, Louisa, and Marsh Run. Although we have transitioned back to pre-pandemic schedules at our generating facilities, we have an ongoing contingency plan for staffing at these facilities. We have developed and implemented procedures to protect our employees from potential exposure to COVID-19 at our facilities, including daily temperature checks, personal protection equipment, and social distancing. Beginning in mid-March 2020, the majority of our headquarters personnel began telecommuting with no disruption in business operations. We currently anticipate that our headquarters personnel will return to the office during the second and third quarters of 2021.

The Commonwealth of Virginia has issued workplace regulations related to infectious disease prevention. All employers covered by these regulations must comply with mandatory requirements to protect employees from workplace exposure to COVID-19, and we are subject to these regulations for our operations located in Virginia. We have not had, nor do we anticipate that we will have, a material impact on our operations or costs due to compliance with these regulations.

Ongoing Considerations

We are continuing to monitor ways in which the COVID-19 pandemic could affect our operations, results of operations, financial condition, and cash flows. The extent to which the pandemic will impact us is uncertain and will depend on numerous evolving factors that we may not be able to accurately predict, including the duration and scope of the pandemic and the actions taken in response.

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 months ended March 31, 2021 and 2020, were as follows:

	Three Months Ended March 31,
	2021		2020		Change
Heating degree days		1,958		1,509		29.8	%
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, 2021 and 2020, were as follows:

	Three Months Ended March 31,
	2021			2020
	(in MWh and percentages)
Generated:
Wildcat Point	534,036	16.1	%	910,835	29.1	%
North Anna	436,693	13.2		491,914	15.7
Clover	185,594	5.6		64,652	2.0
Louisa	71,077	2.1		6,681	0.2
Marsh Run	104,727	3.2		12,810	0.4
Distributed Generation	451	—		213	—
Total Generated	1,332,578	40.2		1,487,105	47.4
Purchased:
Other than renewable:
Long-term and short-term	935,169	28.2		703,260	22.5
Spot market	810,898	24.5		705,785	22.5
Total Other than renewable	1,746,067	52.7		1,409,045	45.0
Renewable ⁽¹⁾	237,028	7.1		238,068	7.6
Total Purchased	1,983,095	59.8		1,647,113	52.6
Total Available Energy	3,315,673	100.0	%	3,134,218	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 to our member distribution cooperatives, are significantly affected by the operations of our generating facilities, which are under dispatch direction of PJM. For further discussion of PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2020 Annual Report on Form 10-K.

Operational Availability

The operational availability of our owned generating resources for the three months ended March 31, 2021 and 2020, was as follows:

	Three Months Ended March 31,
	2021			2020
Wildcat Point		99.5	%		92.6	%
North Anna		90.0			100.0
Clover		83.9			71.4
Louisa		98.7			97.4
Marsh Run		99.6			100.0

Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the three months ended March 31, 2021 and 2020, as a percentage of maximum dependable capacity rating of the facilities, was as follows:

	Three Months Ended March 31,
	2021			2020
Wildcat Point		25.0	%		64.4	%
North Anna		92.2			102.7
Clover		20.1			7.0

Sales to Member Distribution Cooperatives

Revenues from sales to our member distribution cooperatives are a function of our formula rate for sales of power and sales of renewable energy credits to our member distribution cooperatives, and our member distribution cooperatives’ customers’ requirements for power. See “Factors Affecting Results—Formula Rate” above.

Sales to Non-members

Revenues from sales to non-members consist of sales of excess purchased and generated energy and capacity, and sales of renewable energy credits. We primarily sell excess energy to PJM under its rates for providing energy imbalance service. Excess energy is the result of changes in our purchased power portfolio, differences between actual and forecasted needs, and changes in market conditions.

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. Our operating revenues and energy sales in MWh by type of purchaser for the three months ended March 31, 2021 and 2020, were as follows:

	Three Months Ended March 31,
	2021		2020
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Energy revenues	$	90,834	$	98,921
Renewable energy credits		9		—
Demand revenues		93,900		105,244
Total revenues from sales to member distribution cooperatives		184,743		204,165
Non-members:
Energy revenues		6,191		4,477
Renewable energy credits		183		104
Total revenues from sales to non-members		6,374		4,581
Total operating revenues	$	191,117	$	208,746

Energy sales to:	(in MWh)
Member distribution cooperatives		3,136,512		2,873,392
Non-members		161,000		236,959
Total energy sales		3,297,512		3,110,351

Average cost of energy to member distribution cooperatives (per MWh)	$	28.96	$	34.43
Average total cost to member distribution cooperatives (per MWh)	$	58.90	$	71.05

Member Distribution Cooperatives

For the three months ended March 31, 2021, total revenues from sales to our member distribution cooperatives decreased $19.4 million, or 9.5%, as compared to the same period in 2020. Energy revenues decreased $8.1 million, or 8.2%, primarily due to the 15.9% decrease in the average cost of energy for the three months ended March 31, 2021, partially offset by the 9.2% increase in energy sales in MWh to our member distribution cooperatives. Demand revenues decreased $11.3 million, or 10.8%, substantially due to the decrease in capacity-related purchased power expense.

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

Date	% Change
January 1, 2020		(16.2	)
January 1, 2021		(15.9	)

Operating Expenses

The following is a summary of the components of our operating expenses for the three months ended March 31, 2021 and 2020:

	Three Months Ended March 31,
	2021			2020
	(in thousands)
Fuel	$	39,754		$	42,578
Purchased power		70,992			92,890
Transmission		31,626			33,916
Deferred energy		(15,940	)		(25,135	)
Operations and maintenance		16,436			13,742
Administrative and general		10,880			11,856
Depreciation and amortization		17,676			17,522
Amortization of regulatory asset/(liability), net		2,487			(790	)
Accretion of asset retirement obligations		1,415			1,365
Taxes, other than income taxes		2,425			2,422
Total Operating Expenses	$	177,751		$	190,366

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 $12.6 million, or 6.6%, for the three months ended March 31, 2021, as compared to the same period in 2020, primarily as a result of the decrease in purchased power expense, partially offset by the increase in deferred energy expense.

•

Purchased power expense, which includes the cost of purchased energy and capacity, decreased $21.9 million, or 23.6%, primarily due to the decrease in purchased energy costs. Purchased energy costs decreased $13.9 million, or 16.9%, due to the 30.9% decrease in the average cost of purchased energy. This decrease was partially offset by the 20.4% increase in the volume of purchased energy, primarily as a result of decreased generation from our owned facilities related to PJM’s economic dispatch. The decrease in the average cost of purchased energy was partially due to the expiration of a long-term purchased power contract on May 31, 2020, which was replaced by lower cost purchased energy. Purchased capacity costs decreased $8.0 million, or 75.7%, due to the decrease in costs to meet our PJM capacity obligation.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, increased $9.2 million for the three months ended March 31, 2021. For the three months ended March 31, 2021 and 2020, we under-collected $15.9 million and $25.1 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 of our 2020 Annual Report on Form 10-K.

Other Items

Interest Charges, Net

The primary factors affecting our interest charges, net are issuance of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility, and capitalized interest. The major components of interest charges, net for the three months ended March 31, 2021 and 2020, were as follows:

	Three Months Ended March 31,
	2021			2020
	(in thousands)
Interest on long-term debt	$	(13,973	)	$	(14,501	)
Interest on revolving credit facility		(95	)		(961	)
Other interest		(130	)		(158	)
Total interest charges		(14,198	)		(15,620	)
Allowance for borrowed funds used during construction		188			83
Interest charges, net	$	(14,010	)	$	(15,537	)

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, 2021, as compared to the same period in 2020.

Financial Condition

The principal changes in our financial condition from December 31, 2020 to March 31, 2021, were caused by decreases in accounts receivable–members, deferred energy, and accounts payable–members; and increases in accrued expenses and regulatory liabilities.

•

Accounts receivable–members decreased $32.7 million due to the $27.5 million decrease in wholesale power invoices for March 2021 as compared to December 2020 and the $5.2 million decrease in member distribution cooperatives’ extended payment balances.

•

Deferred energy decreased $15.9 million as a result of the under-collection of our energy costs in 2021. The deferred energy balance was an over-collection of $23.1 million and $7.2 million as of December 31, 2020, and March 31, 2021, respectively.

•

Accounts payable–members decreased $9.9 million due to the $5.4 million decrease in member prepayments and the $4.5 million decrease in the amounts owed to our member distribution cooperatives under Margin Stabilization.

•

Accrued expenses increased $14.9 million due to accrued interest on long-term debt and accrued property taxes.

•

Regulatory liabilities increased $10.2 million primarily due to increases in the unrealized gains on the North Anna nuclear decommissioning fund and derivatives.

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 2021 and 2020, our operating activities provided cash flows of $56.1 million and $92.8 million, respectively. Operating activities in 2021 were primarily impacted by the $37.0 million change in current assets, the $15.9 million change in deferred energy, and the $10.6 million change in regulatory assets and liabilities.

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 facilities.

Uses

Our uses of liquidity and capital relate to funding our working capital needs, investment activities, and financing activities. Substantially all our investment activities relate to capital expenditures in connection with our generating facilities. We expect that cash flows from our operations, borrowings under our revolving credit facility, and financings in the debt capital markets will be sufficient to meet our currently anticipated future operational and capital requirements.

ITEM 3. QUANTITATIVE AND QUALITATIVE

DISCLOSURES ABOUT MARKET RISK

No material changes occurred in our exposure to market risk during the first quarter of 2021 .

ITEM 4. CONTROLS AND PROCEDURES

As of the end of the period covered by this report, our management, including the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer, conducted an evaluation of the effectiveness of our disclosure controls and procedures. Based upon that evaluation, the President and Chief Executive Officer, and Senior Vice President and Chief Financial Officer, concluded that our disclosure controls and procedures are effective in ensuring that all material information required to be filed in this report has been made known to them in a timely matter. We have established a Disclosure Assessment Committee comprised of members of our senior and middle management to assist in this evaluation.

There have been no material changes in our internal controls over financial reporting or in other factors that could significantly affect such controls during the past fiscal quarter. We have not identified any adverse impact on our internal controls over financial reporting despite the majority of our headquarters personnel telecommuting due to the COVID-19 pandemic. The design of our processes and controls allows for remote execution with accessibility to secure data. We are continually monitoring and assessing the COVID-19 pandemic to minimize the impact, if any, on the design and operating effectiveness of our internal controls.

OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Recovery of Costs from PJM

In the first quarter of 2014, we incurred approximately $14.9 million of costs related to the dispatch of our combustion turbine facilities for which we were directed by PJM to incur and were subsequently denied reimbursement. Our pursuit of recovery of these costs from PJM before FERC was unsuccessful.

We are pursuing recovery as a separate breach of an oral contract claim in the Circuit Court for the County of Henrico in the Commonwealth of Virginia. In 2019, PJM removed the matter to United States District Court for the Eastern District of Virginia and filed a motion to dismiss, and we filed a motion to remand the matter to state court. In 2020, the court granted PJM’s motion to dismiss and denied our motion to remand the matter to state court. We filed a notice of appeal to the United States Court of Appeals for the Fourth Circuit and oral arguments have been tentatively scheduled for September 2021. We have not recorded a receivable related to this matter.

Other Matters

Other than the issues discussed above and certain other 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 of our 2020 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 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		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Label Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

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 11, 2021		/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