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 ☒

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

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

	September 30, 2020			December 31, 2019			March 31, 2021			December 31, 2020
	(in thousands)						(in thousands)
	(unaudited)						(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,525,477		$	2,531,986		$	2,537,293		$	2,536,395
Less accumulated depreciation		(960,520	)		(927,065	)		(1,001,287	)		(984,076	)
Net Property, plant, and equipment		1,564,957			1,604,921			1,536,006			1,552,319
Nuclear fuel, at amortized cost		12,313			20,705			14,722			17,321
Construction work in progress		43,112			31,462			42,694			38,810
Net Electric Plant		1,620,382			1,657,088			1,593,422			1,608,450
Investments:
Nuclear decommissioning trust		217,126			211,108			250,290			242,337
Unrestricted investments and other		2,276			5,380			2,317			2,311
Total Investments		219,402			216,488			252,607			244,648
Current Assets:
Cash and cash equivalents		70,364			3,469			55,232			9,288
Restricted cash and cash equivalents		—			24,230
Accounts receivable		9,783			12,422			13,342			16,909
Accounts receivable–members		73,156			101,185			47,113			79,813
Fuel, materials, and supplies		57,928			62,083			62,502			61,273
Deferred energy		—			3,548
Prepayments and other		2,996			4,702			3,650			5,598
Total Current Assets		214,227			211,639			181,839			172,881
Deferred Charges and Other Assets:
Regulatory assets		28,818			57,742			26,192			31,131
Other assets		9,650			26,287			8,998			10,534
Total Deferred Charges and Other Assets		38,468			84,029			35,190			41,665
Total Assets	$	2,092,479		$	2,169,244		$	2,063,058		$	2,067,644
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	450,545		$	441,311		$	456,310		$	453,470
Non-controlling interest		5,858			5,846			5,848			5,853
Total Patronage capital and Non-controlling interest		456,403			447,157			462,158			459,323
Long-term debt		1,118,241			1,117,867			1,069,441			1,069,324
Revolving credit facility		—			67,200
Total Long-term debt and Revolving credit facility		1,118,241			1,185,067
Total Capitalization		1,574,644			1,632,224			1,531,599			1,528,647
Current Liabilities:
Long-term debt due within one year		40,792			40,792			49,041			49,041
Accounts payable		53,341			147,916			57,595			61,044
Accounts payable–members		85,646			26,804			60,599			70,546
Accrued expenses		23,172			5,850			21,157			6,292
Deferred energy		5,100			—			7,171			23,112
Total Current Liabilities		208,051			221,362			195,563			210,035
Deferred Credits and Other Liabilities:
Asset retirement obligations		177,766			173,669			180,548			179,133
Regulatory liabilities		129,264			117,483			152,941			142,724
Other liabilities		2,754			24,506			2,407			7,105
Total Deferred Credits and Other Liabilities		309,784			315,658			335,896			328,962
Commitments and Contingencies		—			—			—			—
Total Capitalization and Liabilities	$	2,092,479		$	2,169,244		$	2,063,058		$	2,067,644

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2020			2019			2020			2019			2021			2020
	(in thousands)												(in thousands)
Operating Revenues	$	216,281		$	252,729		$	614,589		$	708,493		$	191,117		$	208,746
Operating Expenses:
Fuel		45,893			51,000			111,277			143,921			39,754			42,578
Purchased power		47,721			83,851			200,756			238,828			70,992			92,890
Transmission		31,815			38,107			98,737			121,476			31,626			33,916
Deferred energy		25,691			15,403			8,648			17,855			(15,940	)		(25,135	)
Operations and maintenance		16,490			23,721			46,524			59,638			16,436			13,742
Administrative and general		10,653			11,358			32,817			38,395			10,880			11,856
Depreciation and amortization		17,423			17,207			52,447			51,539			17,676			17,522
Amortization of regulatory asset/(liability), net		7,895			(9,163	)		7,044			(26,342	)		2,487			(790	)
Accretion of asset retirement obligations		1,366			1,386			4,096			4,154			1,415			1,365
Taxes, other than income taxes		2,281			2,350			7,130			7,185			2,425			2,422
Total Operating Expenses		207,228			235,220			569,476			656,649			177,751			190,366
Operating Margin		9,053			17,509			45,113			51,844			13,366			18,380
Other income (expense), net		(18	)		(41	)		(78	)		(43	)		71			(57	)
Investment income		8,800			1,358			10,052			5,369			3,406			350
Interest charges, net		(14,845	)		(15,648	)		(45,837	)		(47,519	)		(14,010	)		(15,537	)
Income taxes		2			(4	)		(4	)		(19	)		2			(3	)
Net Margin including Non-controlling interest		2,992			3,174			9,246			9,632			2,835			3,133
Non-controlling interest		4			(16	)		(12	)		(54	)		5			(9	)
Net Margin attributable to ODEC		2,996			3,158			9,234			9,578			2,840			3,124
Patronage Capital - Beginning of Period		447,549			435,083			441,311			428,663			453,470			441,311
Patronage Capital - End of Period	$	450,545		$	438,241		$	450,545		$	438,241		$	456,310		$	444,435

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

	Nine Months Ended September 30,							Three Months Ended March 31,
	2020				2019			2021			2020
	(in thousands)							(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	9,246			$	9,632		$	2,835		$	3,133
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		52,447				51,539			17,676			17,522
Other non-cash charges		12,864				12,674			4,129			4,471
Change in current assets		36,529				(11,806	)		36,986			37,332
Change in deferred energy		8,648				17,855			(15,940	)		(25,135	)
Change in current liabilities		47,286				18,063			2,981			53,259
Change in regulatory assets and liabilities		44,330				(38,127	)		10,594			5,886
Change in other assets and other liabilities		(4,886	)			(3,225	)
Change in deferred charges and other assets and deferred credits and other liabilities									(3,167	)		(3,690	)
Net Cash Provided by Operating Activities		206,464				56,605			56,094			92,778
Investing Activities:
Purchases of held to maturity securities		—				(2,875	)
Proceeds from sale of held to maturity securities		3,115				3,078
Purchases of available for sale securities		(12,400	)			(53,828	)
Proceeds from sale of available for sale securities		12,400				53,828
Increase in other investments		(9,648	)	��		(4,069	)		(3,392	)		(78	)
Electric plant additions		(89,831	)			(28,747	)		(6,758	)		(47,516	)
Net Cash Used for Investing Activities		(96,364	)			(32,613	)		(10,150	)		(47,594	)
Financing Activities:
Debt issuance costs		(235	)			(257	)		—			(235	)
Draws on revolving credit facility		349,225				167,250			—			349,225
Repayments on revolving credit facility		(416,425	)			(167,250	)		—			(166,425	)
Net Cash Used for Financing Activities		(67,435	)			(257	)
Net Cash Provided by Financing Activities									—			182,565
Net Change in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents		42,665				23,735			45,944			227,749
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - Beginning of Period		27,699				22,978			9,288			27,699
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - End of Period	$	70,364			$	46,713		$	55,232		$	255,448

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

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 ~~September 30, 2020,~~March 31, 2021, our consolidated results of operations for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ and cash flows for the ~~nine~~three months ended ~~September 30, 2020~~March 31, 2021 and ~~2019.~~2020. The consolidated results of operations for the three ~~and nine~~ months ended ~~September 30, 2020,~~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 ~~2019~~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 ~~$5.9 million and~~ $5.8 million as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019, respectively.~~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 ~~but~~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.

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 ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019:~~ 2020:

			Quoted Prices								Quoted Prices
			in Active		Significant						in Active		Significant
			Markets for		Other		Significant				Markets for		Other		Significant
			Identical		Observable		Unobservable				Identical		Observable		Unobservable
	September 30,		Assets		Inputs		Inputs		March 31,		Assets		Inputs		Inputs
	2020		(Level 1)		(Level 2)		(Level 3)		2021		(Level 1)		(Level 2)		(Level 3)
	(in thousands)								(in thousands)
Nuclear decommissioning trust ⁽¹⁾	$	81,118	$	81,118	$	—	$	—	$	73,029	$	73,029	$	—	$	—
Nuclear decommissioning trust - net asset value ⁽¹⁾⁽²⁾		136,008		—		—		—		177,261		—		—		—
Unrestricted investments and other ⁽³⁾		132		—		132		—		172		—		172		—
Derivatives - gas and power ⁽⁴⁾		13,274		10,931		1,179		1,164		5,145		4,531		526		88
Total Financial Assets	$	230,532	$	92,049	$	1,311	$	1,164	$	255,607	$	77,560	$	698	$	88

Derivatives - gas and power ⁽⁴⁾	$	2,105	$	—	$	2,105	$	—	$	1,409	$	—	$	1,409	$	—
Total Financial Liabilities	$	2,105	$	—	$	2,105	$	—	$	1,409	$	—	$	1,409	$	—

			Quoted Prices								Quoted Prices
			in Active		Significant						in Active		Significant
			Markets for		Other		Significant				Markets for		Other		Significant
			Identical		Observable		Unobservable				Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs		December 31,		Assets		Inputs		Inputs
	2019		(Level 1)		(Level 2)		(Level 3)		2020		(Level 1)		(Level 2)		(Level 3)
	(in thousands)								(in thousands)
Nuclear decommissioning trust ⁽¹⁾	$	64,504	$	64,504	$	—	$	—	$	76,037	$	76,037	$	—	$	—
Nuclear decommissioning trust - net asset value ⁽¹⁾⁽²⁾		146,604		—		—		—		166,300		—		—		—
Unrestricted investments and other ⁽³⁾		126		—		126		—		166		—		166		—
Derivatives - gas and power ⁽⁴⁾		1,013		—		—		1,013		3,478		1,582		480		1,416
Total Financial Assets	$	212,247	$	64,504	$	126	$	1,013	$	245,981	$	77,619	$	646	$	1,416

Derivatives - gas and power ⁽⁴⁾	$	24,125	$	17,109	$	7,016	$	—	$	6,406	$	—	$	6,406	$	—
Total Financial Liabilities	$	24,125	$	17,109	$	7,016	$	—	$	6,406	$	—	$	6,406	$	—

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 ~~2019~~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					Quantity
		As of September 30,		As of December 31,			As of March 31,		As of December 31,
Commodity	Unit of Measure	2020		2019		Unit of Measure	2021		2020
Natural gas	MMBTU		57,190,000		73,560,000	MMBTU		46,440,000		55,630,000
Purchased power - financial transmission rights	MWh		4,860,209		5,771,291	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					Fair Value
		As of September 30,		As of December 31,			As of March 31,		As of December 31,
	Balance Sheet Location	2020		2019		Balance Sheet Location	2021		2020
		(in thousands)					(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	12,110	$	—	Other assets	$	5,057	$	2,062
Financial transmission rights	Other assets		1,164		1,013	Other assets		88		1,416
Total derivatives in an asset position		$	13,274	$	1,013		$	5,145	$	3,478

Derivatives in a liability position:
Natural gas futures contracts	Other liabilities	$	2,105	$	24,125	Other liabilities	$	1,409	$	6,406
Total derivatives in a liability position		$	2,105	$	24,125		$	1,409	$	6,406

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,~~March 31, 2021 and 2020 ~~and 2019~~

																									Amount of Gain
																									(Loss) Reclassified
	Amount of Gain					Location of	Amount of Gain (Loss) Reclassified												Amount of Gain					Location of	from Regulatory
	(Loss) Recognized					Gain (Loss)	from Regulatory Asset/Liability												(Loss) Recognized					Gain (Loss)	Asset/Liability
	in Regulatory					Reclassified	into Income for the												in Regulatory					Reclassified	into Income for the
Derivatives	Asset/Liability for					from Regulatory	Three Months						Nine Months						Asset/Liability for					from Regulatory	Three Months
Accounted for Utilizing	Derivatives as of					Asset/Liability	Ended						Ended						Derivatives as of					Asset/Liability	Ended
Regulatory Accounting	September 30,					into Income	September 30,						September 30,						March 31,					into Income	March 31,
	2020		2019				2020			2019			2020			2019			2021		2020				2021			2020
	(in thousands)						(in thousands)												(in thousands)						(in thousands)
Natural gas futures contracts	$	9,090	$	(13,603	)	Fuel	$	(6,621	)	$	(5,175	)	$	(33,813	)	$	(15,081	)	$	3,711	$	(19,521	)	Fuel	$	(4,365	)	$	(21,466	)
Purchased power		1,164		1,053		Purchased power		3,192			3,334			(1,291	)		(2,068	)		88		532		Purchased power		3,612			(3,585	)
Total	$	10,254	$	(12,550	)		$	(3,429	)	$	(1,841	)	$	(35,104	)	$	(17,149	)	$	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.

Investments were as follows as of ~~September 30, 2020~~March 31, 2021 and December 31, ~~2019:~~2020:

			Gross		Gross									Gross		Gross
			Unrealized		Unrealized			Fair		Carrying				Unrealized		Unrealized		Fair		Carrying
Description	Cost		Gains		Losses			Value		Value		Cost		Gains		Losses		Value		Value
	(in thousands)											(in thousands)
September 30, 2020
March 31, 2021
Nuclear decommissioning trust ⁽¹⁾
Debt securities	$	60,809	$	7,656	$	—		$	68,465	$	68,465	$	68,197	$	4,188	$	—	$	72,385	$	72,385
Equity securities		81,662		59,375		(5,030	)		136,007		136,007		92,567		84,694		—		177,261		177,261
Cash and other ⁽²⁾		12,654		—		—			12,654		12,654		644		—		—		644		644
Total Nuclear Decommissioning Trust	$	155,125	$	67,031	$	(5,030	)	$	217,126	$	217,126	$	161,408	$	88,882	$	—	$	250,290	$	250,290

Other
Equity securities	$	111	$	21	$	—		$	132	$	132	$	132	$	39	$	—	$	171	$	171
Non-marketable equity investments		2,144		2,403		—			4,547		2,144		2,146		2,372		—		4,518		2,146
Total Other	$	2,255	$	2,424	$	—		$	4,679	$	2,276	$	2,278	$	2,411	$	—	$	4,689	$	2,317
										$	219,402									$	252,607

December 31, 2019
December 31, 2020
Nuclear decommissioning trust ⁽¹⁾
Debt securities	$	59,748	$	4,325	$	—		$	64,073	$	64,073	$	66,727	$	7,493	$	—	$	74,220	$	74,220
Equity securities		85,303		63,858		(2,557	)		146,604		146,604		89,472		76,828		—		166,300		166,300
Cash and other		431		—		—			431		431		1,817		—		—		1,817		1,817
Total Nuclear Decommissioning Trust	$	145,482	$	68,183	$	(2,557	)	$	211,108	$	211,108	$	158,016	$	84,321	$	—	$	242,337	$	242,337

Unrestricted investments
Government obligations	$	2,869	$	4	$	—		$	2,873	$	2,869
Debt securities		240		—		—			240		240
Total Unrestricted Investments	$	3,109	$	4	$	—		$	3,113	$	3,109

Other
Equity securities	$	110	$	15	$	—		$	125	$	125	$	132	$	34	$	—	$	166	$	166
Non-marketable equity investments		2,146		2,176		—			4,322		2,146		2,145		2,340		—		4,485		2,145
Total Other	$	2,256	$	2,191	$	—		$	4,447	$	2,271	$	2,277	$	2,374	$	—	$	4,651	$	2,311
										$	216,488									$	244,648

Contractual maturities of debt securities as of ~~September 30, 2020,~~March 31, 2021, were as follows:


Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total		Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)										(in thousands)
Other ⁽¹⁾	$	—	$	—	$	68,465	$	—	$	68,465	$	—	$	—	$	72,385	$	—	$	72,385
Held to maturity		—		—		—		—		—
Total	$	—	$	—	$	68,465	$	—	$	68,465	$	—	$	—	$	72,385	$	—	$	72,385

We own Wildcat Point, a 973 MW (net capacity entitlement) natural gas-fueled combined cycle generation facility. Wildcat Point achieved commercial operation on April 17, 2018. In 2017, WOPC, a joint venture between PCL Industrial Construction Company and Sargent & Lundy, L.L.C., as EPC contractor, made a claim against Alstom and us for recovery of additional amounts under the EPC contract for Wildcat Point. Additionally, in 2017, we filed a complaint alleging that WOPC breached the EPC contract. Subsequently, the United States District Court for the Eastern District of Virginia ordered that the WOPC complaint against Alstom and us, our complaint against WOPC, and a separate complaint filed by WOPC against Mitsubishi, be consolidated. In December 2019, ODEC and WOPC held formal settlement discussions and we recognized the probable impact of the settlement as of December 31, 2019, resulting in a $29.6 million increase to property, plant, and equipment. On January 9, 2020, ODEC and WOPC settled their dispute and ODEC was dismissed as a party from the case.

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 ~~September 30,~~March 31, 2021 and December 31, 2020, we had no borrowings ~~outstanding under this facility~~ and had a $0.5 million letter of ~~credit. As of December 31, 2019, we had $67.2 million in borrowings~~credit outstanding under this ~~facility and a $0.5 million letter of credit.~~facility.

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 September 30,				As of March 31,
	2020		2019		2021		2020
	(in thousands)				(in thousands)
Cash and cash equivalents	$	70,364	$	22,583	$	55,232	$	231,128
Restricted cash and cash equivalents		—		24,130		—		24,320
Total	$	70,364	$	46,713	$	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.

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 ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ we had no sales to TEC and TEC had no sales to third parties.

Our operating revenues for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2020		2019		2020		2019		2021		2020
	(in thousands)								(in thousands)
Member distribution cooperatives
Sales to member distribution cooperatives, excluding renewable energy credit sales	$	201,620	$	237,661	$	589,648	$	678,789	$	184,734	$	204,165
Renewable energy credit sales to member distribution cooperatives		13		4		26		21		9		—
Total sales to member distribution cooperatives	$	201,633	$	237,665	$	589,674	$	678,810	$	184,743	$	204,165

Non-members
Sales to non-members, excluding renewable energy credit sales	$	9,314	$	11,812	$	19,477	$	25,011	$	6,191	$	4,477
Renewable energy credit sales to non-members		5,334		3,252		5,438		4,672		183		104
Total sales to non-members	$	14,648	$	15,064	$	24,915	$	29,683	$	6,374	$	4,581

Total operating revenues	$	216,281	$	252,729	$	614,589	$	708,493	$	191,117	$	208,746

~~On April 12, 2020, the governor of Virginia signed legislation that requires that all investor-owned utility generating facilities that emit CO~~₂ as a by-product of combustion cease commercial operation by December 31, 2045. This includes the Clover generation facility, which we co-own with Virginia Power, an investor-owned utility. However, if the reliability or security of providing electric service to customers is threatened, a petition may be made by Virginia Power to the Virginia State Corporation Commission requesting relief from the closure requirement. Clover’s current depreciation rates are based on a useful life through 2050 and due to the uncertainty of the reliability requirements in the future, we have concluded that a change in useful life is not necessary at this time. For further discussion of Virginia CO₂~~Regulation, see “Regulation—Virginia CO~~₂~~Regulation” in Part 1, Item 1 Business of our 2019 Annual Report on Form 10-K.~~

In June 2016, the FASB issued ASU 2016-13 Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses in Financial Instruments. FASB issued subsequent amendments to the initial guidance in November 2018 with ASU No. 2018-19, in April 2019 with ASU No. 2019-04, and in May 2019 with ASU No. 2019-05. The ASU amends the guidance on the impairment of financial instruments and adds an impairment model, known as the current expected credit loss (“CECL”) model. The CECL model requires an entity to recognize its current estimate of all expected credit losses, rather than incurred losses, and applies to trade receivables and other receivables. The CECL

model is designed to capture expected credit losses through the establishment of an allowance account, which will be presented as an offset to the amortized cost basis of the related financial asset. The new guidance is effective for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, and is applied using the modified-retrospective approach. We adopted this standard for the fiscal year beginning January 1, 2020, and it did not have a material impact on our financial statements.

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.

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,~~to: general business ~~conditions,~~conditions; demand for ~~energy,~~energy; federal and state legislative and regulatory actions, and legal and administrative ~~proceedings,~~proceedings; the impact of the COVID-19 pandemic on our business, financial condition, and future operations; changes in and compliance with environmental laws and ~~policies,~~regulations; general credit and capital market ~~conditions,~~conditions; weather ~~conditions,~~conditions; the cost of commodities used in our ~~industry,~~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. 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.

As of ~~September 30, 2020,~~March 31, 2021, there have been no significant changes in our critical accounting policies as disclosed in our ~~2019~~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.

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.

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, 2020,~~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 ~~milder~~ weather.

We believe our results for the three ~~and nine~~ months ended ~~September 30, 2020,~~March 31, 2021 were not materially impacted by ~~the outbreak in the United States of~~ the COVID-19 pandemic. We believe that other factors described above, such as ~~the decrease~~decreases in our total energy rate, purchased power expense, and PJM’s economic dispatch of our generating facilities, and the impact of ~~milder~~ weather, were the primary drivers of our results for the three ~~and nine~~ months ended ~~September 30, 2020.~~March 31, 2021. We continue to closely monitor how the ~~outbreak~~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.

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:

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 ~~expense,~~costs, administrative and general ~~expense,~~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 ~~nuclear~~ decommissioning ~~expense,~~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:

As stated above, our margin ~~requirements,~~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 upequal 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 ~~and nine~~ months ended ~~September 30, 2020,~~March 31, 2021 and ~~for the nine months ended September 30, 2019; and to increase revenues for the three months ended September 30, 2019.~~2020.

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 ~~2019~~2020 Annual Report on Form 10-K.

For the three ~~and nine~~ months ended ~~September 30, 2020,~~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 ~~financial condition.~~cash flows.

Our total revenues decreased ~~$36.4~~$17.6 million, or ~~14.4%~~8.4%, ~~and $93.9 million, or 13.3%, for the three and nine months ended September 30, 2020, respectively,~~ as compared to the same ~~periods~~period in the prior year. The ~~decreases were~~decrease was primarily due to the ~~16.2%~~15.9% decrease in our total energy rate to our member distribution cooperatives, effective January 1, ~~2020, and the milder~~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.

~~4.6%, respectively,~~increased 9.2% as compared to the same ~~periods~~period in the prior year. We believe a significant portion of the ~~decrease~~increase relates to weather.

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. ~~Although we cannot currently determine the portion of the decrease that may be attributable to the pandemic, we are continuing to evaluate the trends associated with the pandemic.~~

Any decline in our member distribution cooperatives’ power requirements related to the COVID-19 pandemic would result in excess energy which we would sell to PJM, TEC, or third parties; or would result in a reduction of our spot market energy purchases.

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. ~~Our~~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 ~~September 30, 2020,~~March 31, 2021, prepayments totaled ~~$79.2~~$51.8 million and extensions totaled ~~$10.4~~$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 ~~September 30, 2020,~~March 31, 2021, we had no borrowings outstanding under our revolving credit facility and had a cash and cash equivalents balance of ~~$70.4~~$55.2 million.

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. ~~Additionally, beginning~~Beginning in mid-March 2020, the majority of our headquarters personnel began telecommuting with no disruption in business ~~operations~~operations. We currently anticipate that our headquarters personnel will return to the office during the second and ~~will continue telecommuting through at least the end~~third quarters of ~~2020.~~2021.

~~In July 2020, the~~The Commonwealth of Virginia has issued ~~the Emergency Temporary Standard~~ workplace regulations related to infectious disease prevention~~Infectious Disease Prevention: SARS-CoV-2 Virus That Causes COVID-19 regulation.~~. All employers covered by ~~this regulation~~these regulations must comply with mandatory requirements to protect employees from workplace exposure to COVID-19, and we are subject to ~~this regulation~~these regulations for our operations located in Virginia. We have not had, nor do ~~not~~we anticipate that ~~compliance under this regulation~~we will ~~result in~~have, a material impact on our operations or ~~costs.~~costs due to compliance with these regulations.

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. ~~See “Part II Other Information—Item 1A. Risk Factors.”~~

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,~~March 31, 2021 and 2020, ~~and 2019,~~ were as follows:

	Three Months Ended September 30,							Nine Months Ended September 30,							Three Months Ended March 31,
	2020		2019		Change			2020		2019		Change			2021		2020		Change
Heating degree days		—		—		—	%		1,714		2,016		(15.0	)%		1,958		1,509		29.8	%
Cooling degree days		1,076		1,138		(5.4	)		1,361		1,553		(12.4	)		—		—	—

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,~~March 31, 2021 and 2020, ~~and 2019,~~ were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2020			2019			2020			2019			2021			2020
	(in MWh and percentages)												(in MWh and percentages)
Generated:
Wildcat Point	840,561	24.5	%	1,069,230	30.5	%	2,336,129	25.3	%	3,202,892	33.5	%	534,036	16.1	%	910,835	29.1	%
North Anna	434,328	12.7		424,494	12.1		1,384,719	15.0		1,281,276	13.4		436,693	13.2		491,914	15.7
Clover	353,645	10.3		274,847	7.8		487,126	5.3		422,084	4.4		185,594	5.6		64,652	2.0
Louisa	198,015	5.8		237,004	6.8		245,949	2.7		392,469	4.1		71,077	2.1		6,681	0.2
Marsh Run	319,951	9.4		317,257	9.0		403,827	4.4		614,806	6.5		104,727	3.2		12,810	0.4
Distributed Generation	1,623	—		1,324	—		2,266	—		2,086	—		451	—		213	—
Total Generated	2,148,123	62.7		2,324,156	66.2		4,860,016	52.7		5,915,613	61.9		1,332,578	40.2		1,487,105	47.4
Purchased:
Other than renewable:
Long-term and short-term	450,507	13.1		610,921	17.4		1,860,704	20.1		1,637,342	17.1		935,169	28.2		703,260	22.5
Spot market	711,202	20.7		454,739	13.0		1,955,875	21.2		1,464,187	15.3		810,898	24.5		705,785	22.5
Total Other than renewable	1,161,709	33.8		1,065,660	30.4		3,816,579	41.3		3,101,529	32.4		1,746,067	52.7		1,409,045	45.0
Renewable ⁽¹⁾	118,465	3.5		118,886	3.4		553,300	6.0		542,672	5.7		237,028	7.1		238,068	7.6
Total Purchased	1,280,174	37.3		1,184,546	33.8		4,369,879	47.3		3,644,201	38.1		1,983,095	59.8		1,647,113	52.6
Total Available Energy	3,428,297	100.0	%	3,508,702	100.0	%	9,229,895	100.0	%	9,559,814	100.0	%	3,315,673	100.0	%	3,134,218	100.0	%

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 ~~control~~direction of PJM. For further discussion of PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our ~~2019~~2020 Annual Report on Form 10-K.

The operational availability of our owned generating resources for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2020			2019			2020			2019			2021			2020
Wildcat Point		96.3	%		84.2	%		90.7	%		85.6	%		99.5	%		92.6	%
North Anna		90.2			87.5			94.8			88.4			90.0			100.0
Clover		83.0			68.5			66.6			63.0			83.9			71.4
Louisa		98.0			94.7			96.3			94.3			98.7			97.4
Marsh Run		100.0			99.3			95.5			97.2			99.6			100.0

The output of Wildcat Point, North Anna, and Clover for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ as a percentage of maximum dependable capacity rating of the facilities, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2020			2019			2020			2019			2021			2020
Wildcat Point		38.6	%		50.1	%		36.1	%		51.4	%		25.0	%		64.4	%
North Anna		89.6			87.6			95.9			89.1			92.2			102.7
Clover		37.7			29.2			17.4			15.2			20.1			7.0

~~On September 14, 2018, we sold our interest in Rock Springs and related assets to EPRS for $115 million. Prior to the sale, w~~e and EPRS had each individually owned two natural gas-fired combustion turbine units and a 50% undivided interest in related common facilities at Rock Springs. The transaction resulted in a gain of $42.7 million, which our board of directors approved to defer as a regulatory liability. We amortized $5.0 million of the gain in 2018 and the remaining $37.7 million was amortized ratably in 2019.

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.

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.

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 ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2020		2019		2020		2019		2021		2020
	(in thousands)								(in thousands)
Revenues from sales to:
Member distribution cooperatives
Energy revenues	$	106,417	$	128,418	$	285,710	$	357,552	$	90,834	$	98,921
Renewable energy credits		13		4		26		21		9		—
Demand revenues		95,203		109,243		303,938		321,237		93,900		105,244
Total revenues from sales to member distribution cooperatives		201,633		237,665		589,674		678,810		184,743		204,165
Non-members:
Energy revenues		9,314		11,812		19,456	��	24,955		6,191		4,477
Renewable energy credits		5,334		3,252		5,438		4,672		183		104
Demand revenues		—		—		21		56
Total revenues from sales to non-members		14,648		15,064		24,915		29,683		6,374		4,581
Total operating revenues	$	216,281	$	252,729	$	614,589	$	708,493	$	191,117	$	208,746

Energy sales to:	(in MWh)								(in MWh)
Member distribution cooperatives		3,092,128		3,125,704		8,301,242		8,703,657		3,136,512		2,873,392
Non-members		329,464		367,463		881,605		802,902		161,000		236,959
Total energy sales		3,421,592		3,493,167		9,182,847		9,506,559		3,297,512		3,110,351

Average cost of energy to member distribution cooperatives (per MWh)	$	34.42	$	41.08	$	34.42	$	41.08	$	28.96	$	34.43
Average total cost to member distribution cooperatives (per MWh)	$	65.21	$	76.04	$	71.03	$	77.99	$	58.90	$	71.05

For the three ~~and nine~~ months ended ~~September 30, 2020,~~March 31, 2021, total revenues from sales to our member distribution cooperatives decreased ~~$36.0~~$19.4 million, or ~~15.2%~~9.5%, ~~and $89.1 million, or 13.1%, respectively,~~ as compared to the same ~~periods~~period in ~~2019.~~2020. Energy revenues decreased ~~$22.0~~$8.1 million, or ~~17.1%~~8.2%, ~~and $71.8 million, or 20.1%, respectively,~~ primarily due to the ~~16.2%~~15.9% decrease in the average cost of energy for the three ~~and nine~~ months ended ~~September 30, 2020. Additionally,~~March 31, 2021, partially offset by the 9.2% increase in energy sales in MWh to our member distribution ~~cooperatives decreased 1.1% and 4.6%, respectively.~~cooperatives. Demand revenues decreased ~~$14.0~~$11.3 million, or ~~12.9%~~10.8%, ~~and $17.3 million, or 5.4%, respectively, primarily~~substantially due to ~~decreases~~the decrease in capacity-related purchased power ~~expense, transmission expense, and operations and maintenance expense; partially offset by the increase in amortization of regulatory asset/(liability), net.~~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:

The following is a summary of the components of our operating expenses for the three ~~and nine~~ months ended ~~September 30, 2020~~March 31, 2021 and ~~2019:~~2020:

	Three Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,
	2020		2019			2020		2019			2021			2020
	(in thousands)										(in thousands)
Fuel	$	45,893	$	51,000		$	111,277	$	143,921		$	39,754		$	42,578
Purchased power		47,721		83,851			200,756		238,828			70,992			92,890
Transmission		31,815		38,107			98,737		121,476			31,626			33,916
Deferred energy		25,691		15,403			8,648		17,855			(15,940	)		(25,135	)
Operations and maintenance		16,490		23,721			46,524		59,638			16,436			13,742
Administrative and general		10,653		11,358			32,817		38,395			10,880			11,856
Depreciation and amortization		17,423		17,207			52,447		51,539			17,676			17,522
Amortization of regulatory asset/(liability), net		7,895		(9,163	)		7,044		(26,342	)		2,487			(790	)
Accretion of asset retirement obligations		1,366		1,386			4,096		4,154			1,415			1,365
Taxes, other than income taxes		2,281		2,350			7,130		7,185			2,425			2,422
Total Operating Expenses	$	207,228	$	235,220		$	569,476	$	656,649		$	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 ~~$28.0~~$12.6 million, or ~~11.9%, and $87.2 million, or 13.3%~~6.6%, for the three ~~and nine~~ months ended ~~September 30, 2020, respectively,~~March 31, 2021, as compared to the same ~~periods~~period in ~~2019,~~2020, primarily as a result of ~~decreases~~the decrease in ~~fuel expense,~~ purchased power expense, ~~transmission expense, operations and maintenance expense, and for the nine months ended September 30, 2020, deferred energy expense. These decreases were~~ partially offset by the increase in ~~amortization of regulatory asset/(liability), net, and for the three months ended September 30, 2020,~~ deferred energy expense.

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 ~~and nine~~ months ended ~~September 30,~~March 31, 2021 and 2020, ~~and 2019,~~ were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2020			2019			2020			2019			2021			2020
	(in thousands)												(in thousands)
Interest on long-term debt	$	(14,507	)	$	(15,032	)	$	(43,508	)	$	(45,083	)	$	(13,973	)	$	(14,501	)
Interest on revolving credit facility		(280	)		(255	)		(1,964	)		(607	)		(95	)		(961	)
Other interest		(193	)		(500	)		(699	)		(2,199	)		(130	)		(158	)
Total interest charges		(14,980	)		(15,787	)		(46,171	)		(47,889	)		(14,198	)		(15,620	)
Allowance for borrowed funds used during construction		135			139			334			370			188			83
Interest charges, net	$	(14,845	)	$	(15,648	)	$	(45,837	)	$	(47,519	)	$	(14,010	)	$	(15,537	)

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 ~~and nine~~ months ended ~~September 30, 2020,~~March 31, 2021, as compared to the same ~~periods~~period in ~~2019.~~2020.

The principal changes in our financial condition from December 31, ~~2019~~2020 to ~~September 30, 2020,~~March 31, 2021, were caused by decreases in accounts ~~payable, revolving credit facility, regulatory assets,~~receivable–members, deferred energy, and accounts ~~receivable–members, other liabilities, and other assets;~~payable–members; and increases in ~~accounts payable–members~~accrued expenses and ~~accrued expenses.~~regulatory liabilities.

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. We continue to evaluate our sources of liquidity and the appropriate level of cash on hand and will continue to monitor and adjust as necessary to meet our forecasted needs. We have no major new construction projects planned requiring capital and do not anticipate issuing additional long-term debt.

During the first ~~nine~~three months of ~~2020~~2021 and ~~2019,~~2020, our operating activities provided cash flows of ~~$206.5~~$56.1 million and ~~$56.6~~$92.8 million, respectively. Operating activities in ~~2020~~2021 were primarily impacted by the ~~$47.3~~$37.0 million change in current ~~liabilities,~~assets, the ~~$44.3~~$15.9 million change in deferred energy, and the $10.6 million change in regulatory assets and ~~liabilities, and the $36.5 million change in current assets.~~liabilities.

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 ~~through~~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 ~~September 30,~~March 31, 2021 and December 31, 2020, we had no borrowings ~~outstanding under this facility~~ and had a $0.5 million letter of ~~credit. As of December 31, 2019, we had $67.2 million in borrowings~~credit outstanding under this ~~facility and a $0.5 million letter of credit.~~ facility.

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 ~~financings~~issuances of debt in the ~~debt~~ capital markets. These capital expenditures consist primarily of the costs related to the development, construction, acquisition, or improvement of our owned generating facilities.

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.

No material changes occurred in our exposure to market risk during the ~~third~~first quarter of 2021 ~~of 2020.~~.

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 ~~from~~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 ~~most~~the majority of our headquarters personnel telecommuting due to the COVID-19 pandemic. The design of our processes and controls allows for ~~compliance~~remote execution with ~~remote and~~accessibility to secure ~~access to necessary financial information.~~data. We are continually monitoring and assessing the COVID-19 pandemic to minimize the impact, if any, ~~impact~~ on the design and operating effectiveness of our internal controls.

In the first quarter of 2014, we ~~filed a petition at FERC seeking recovery from PJM of~~incurred approximately $14.9 million of ~~unreimbursed~~ costs ~~which were incurred during the first quarter of 2014~~ related to the dispatch of our combustion turbine ~~facilities. In 2015,~~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 denied our petition, we filed a request for rehearing, and FERC issued an order granting rehearing for the limited purpose of FERC's further consideration of the matter. In 2016, FERC denied our request for rehearing and, on June 15, 2018, the United States Court of Appeals for the District of Columbia Circuit denied our Petition for Review. PJM removed the matter to United States District Court for the Eastern District of Virginia in July of 2019 and filed a motion to dismiss. In 2019, we filed a motion to remand the matter to state court. On March 31, 2020, the United States District Court for the Eastern District of Virginia granted PJM’s motion to dismiss and denied our motion to remand. was unsuccessful.

We ~~filed a notice of appeal to the United States Court of Appeals for the Fourth Circuit on jurisdictional grounds and~~ are ~~awaiting the court’s decision. We continue to pursue~~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 than the issues discussed above and certain other legal proceedings arising out of the ordinary course of business that management ~~believ~~esbelieves 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.

Our business and operations, and the operations of our member distribution cooperatives and suppliers, have been and will be impacted by the COVID-19 pandemic and could be similarly impacted by like events in the future.

The recent outbreak of COVID-19 has been declared by the World Health Organization to be a pandemic and has spread across the world, including the United States. Because the severity, magnitude, and duration of the COVID-19 pandemic and its economic consequences are uncertain, rapidly changing, and difficult to predict, the ultimate impact on our operations and financial performance cannot be determined at this time. We expect that the longer the period of economic and global supply chain disruptions continue, the greater the risk that there could be a material adverse impact on our operations, results of operations, financial condition, and cash flows.

ODEC is considered an essential service provider and due to this pandemic we have previously adjusted and may in the future need to adjust the schedules of our workforce at our owned generating facilities that we operate, specifically Wildcat Point, Louisa, and Marsh Run and have a contingency plan for staffing at these facilities. We have ownership interests in North Anna and Clover that are operated by Virginia Power, which has taken similar measures. 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 and will continue telecommuting through at least the end of 2020. There can be no assurance that these measures will fully protect us from the impact of the COVID-19 pandemic.

On June 8, 2020, the National Bureau of Economic Research announced that the U.S. was in a recession. Economic conditions, including a significant increase in unemployment, expiration of federal or state support programs, and state government orders prohibiting disconnection of utilities during a state of emergency, as a result of the COVID-19 pandemic, may make it difficult for some customers of our member distribution cooperatives to pay their power bills. These economic conditions could ultimately affect the timeliness of our member distribution cooperatives’ cash flows and potentially the timing of their payments to us. Our member distribution cooperatives’ ability to collect their costs from their members may have an impact on our financial condition and cash flows.

As the impact of the COVID-19 pandemic on our operations and the economy evolves, we will continue to assess our liquidity needs. A continued worldwide disruption in the availability of credit could materially affect future access to our sources of liquidity. Adverse changes in our credit ratings may require us to provide credit support for some of our obligations and could negatively impact our liquidity and our ability to access capital.Conditions in the financial and credit markets also may limit the availability of funding or increase the cost of funding, which could adversely affect our operations, results of operations, financial condition, and cash flows.

Sustained deterioration in the financial markets could adversely affect the value of our nuclear decommissioning trust and the NRECA Retirement Security Plan, a noncontributory, defined benefit pension plan qualified under Section 401, in which our employees participate. The decline in the value of these funds could ultimately necessitate significant additional contributions by us.

See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a more detailed discussion of the potential impact of the COVID-19 pandemic on our operations and financial results, and the actual operational and financial impacts that we have experienced to date.

In addition to the ~~risk factor above and~~ other information set forth in this report, you should carefully consider the factors discussed in “Risk Factors” in Part I, Item 1A of our ~~2019~~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.

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.

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

Abbreviation or Acronym		Definition

ACES		Alliance for Cooperative Energy Services Power Marketing, LLC

~~Alstom~~		~~Alstom Power, Inc.~~

ASU		Accounting Standards Update

Clover		Clover Power Station

CO₂		~~Carbon dioxide~~

~~EPC~~		~~Engineering, procurement, and construction~~

~~EPRS~~		~~Essential Power Rock Springs, LLC~~

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

~~Mitsubishi~~		~~Mitsubishi Hitachi Power Systems Americas, Inc.~~

MW		~~Megawatt(s)~~

MWh		Megawatt hour(s)

~~NRECA~~		~~National Rural Electric Cooperative Association~~

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.

~~Virginia Power~~		~~Virginia Electric and Power Company~~

Wildcat Point		Wildcat Point Generation Facility

~~WOPC~~		~~White Oak Power Constructors~~

XBRL		Extensible Business Reporting Language

		Page Number

PART I. Financial Information

Item 1. Financial Statements

Condensed Consolidated Balance Sheets – ~~September 30, 2020~~March 31, 2021 (unaudited) and December 31, ~~2019~~2020		4

Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~		5

Condensed Consolidated Statements of Cash Flows (unaudited) – ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2021 and 2020 ~~and 2019~~		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		2423

PART II. Other Information		2524

Item 1. Legal Proceedings		2524

Item 1A. Risk Factors		2524
~~Item 5. Other Information~~		26

Item 6. Exhibits		2725

Date	% Change
January 1, ~~2019~~		~~(1.3~~	)
~~January 1,~~ 2020		(16.2	)
January 1, 2021		(15.9	)


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


	OLD DOMINION ELECTRIC COOPERATIVE
		Registrant

Date: ~~November 10, 2020~~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