Old Dominion Electric Cooperative 10-Q 2021 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2021

or

☐ 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.

Large accelerated filer	☐	Accelerated filer	☐
Non-accelerated filer	☒	Smaller reporting company	☐
Emerging growth company	☐

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 0 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
MMBTU	One Million British Thermal Units
MWh	Megawatt hour(s)
North Anna	North Anna Nuclear Power Station
NYMEX	New York Mercantile Exchange
ODEC, We, Our, Us	Old Dominion Electric Cooperative
PJM	PJM Interconnection, LLC
RTO	Regional transmission organization
TEC	TEC Trading, Inc.
Wildcat Point	Wildcat Point Generation Facility
XBRL	Extensible Business Reporting Language

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OLD DOMINION ELECTRIC COOPERATIVE

INDEX

	Page Number
PART I.  Financial Information
Item 1.  Financial Statements
Condensed Consolidated Balance Sheets – September 30, 2021 (unaudited) and December 31, 2020	4
Condensed Consolidated Statements of Revenues, Expenses, and Patronage Capital (unaudited) – Three and Nine Months Ended September 30, 2021 and 2020	5
Condensed Consolidated Statements of Cash Flows (unaudited) – Nine Months Ended September 30, 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	25
Item 1.  Legal Proceedings	25
Item 1A.  Risk Factors	25
Item 5.  Other Information	25
Item 6.  Exhibits	26

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OLD DOMINION ELECTRIC COOPERATIVE

PART 1.  FINANCIAL INFORMATION

ITEM 1.  FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2021			December 31, 2020
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,543,382		$	2,536,395
Less accumulated depreciation		(1,034,699	)		(984,076	)
Net Property, plant, and equipment		1,508,683			1,552,319
Nuclear fuel, at amortized cost		17,492			17,321
Construction work in progress		40,559			38,810
Net Electric Plant		1,566,734			1,608,450
Investments:
Nuclear decommissioning trust		263,040			242,337
Unrestricted investments and other		2,325			2,311
Total Investments		265,365			244,648
Current Assets:
Cash and cash equivalents		135,111			9,288
Accounts receivable		16,624			16,909
Accounts receivable–members		64,254			79,813
Fuel, materials, and supplies		61,889			61,273
Prepayments and other		3,805			5,598
Total Current Assets		281,683			172,881
Deferred Charges and Other Assets:
Regulatory assets		23,566			31,131
Other assets		110,655			10,534
Total Deferred Charges and Other Assets		134,221			41,665
Total Assets	$	2,248,003		$	2,067,644
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	461,974		$	453,470
Non-controlling interest		5,836			5,853
Total Patronage capital and Non-controlling interest		467,810			459,323
Long-term debt		1,069,682			1,069,324
Total Capitalization		1,537,492			1,528,647
Current Liabilities:
Long-term debt due within one year		49,041			49,041
Accounts payable		67,254			61,044
Accounts payable–members		47,920			70,546
Accrued expenses		22,906			6,292
Deferred energy		10,208			23,112
Total Current Liabilities		197,329			210,035
Deferred Credits and Other Liabilities:
Asset retirement obligations		183,380			179,133
Regulatory liabilities		264,760			142,724
Other liabilities		65,042			7,105
Total Deferred Credits and Other Liabilities		513,182			328,962
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	2,248,003		$	2,067,644

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(in thousands)
Operating Revenues	$	200,967		$	216,281		$	573,568		$	614,589
Operating Expenses:
Fuel		46,953			45,893			113,141			111,277
Purchased power		57,471			47,721			174,142			200,756
Transmission		33,257			31,815			97,125			98,737
Deferred energy		(2,008	)		25,691			(12,903	)		8,648
Operations and maintenance		17,571			16,490			58,126			46,524
Administrative and general		10,572			10,653			32,092			32,817
Depreciation and amortization		17,594			17,423			52,825			52,447
Amortization of regulatory asset/(liability), net		11,494			7,895			15,707			7,044
Accretion of asset retirement obligations		1,417			1,366			4,247			4,096
Taxes, other than income taxes		2,279			2,281			7,173			7,130
Total Operating Expenses		196,600			207,228			541,675			569,476
Operating Margin		4,367			9,053			31,893			45,113
Other income (expense), net		(36	)		(18	)		(6	)		(78	)
Investment income		12,448			8,800			18,489			10,052
Interest charges, net		(13,951	)		(14,845	)		(41,895	)		(45,837	)
Income taxes		2			2			6			(4	)
Net Margin including Non-controlling interest		2,830			2,992			8,487			9,246
Non-controlling interest		5			4			17			(12	)
Net Margin attributable to ODEC		2,835			2,996			8,504			9,234
Patronage Capital - Beginning of Period		459,139			447,549			453,470			441,311
Patronage Capital - End of Period	$	461,974		$	450,545		$	461,974		$	450,545

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

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OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2021			2020
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	8,487		$	9,246
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		52,825			52,447
Other non-cash charges		12,354			12,864
Change in current assets		17,021			36,529
Change in deferred energy		(12,903	)		8,648
Change in current liabilities		2,634			47,286
Change in regulatory assets and liabilities		127,318			44,330
Change in deferred charges and other assets and deferred credits and other liabilities		(42,197	)		(4,886	)
Net Cash Provided by Operating Activities		165,539			206,464
Investing Activities:
Proceeds from sale of held to maturity securities		—			3,115
Purchases of available for sale securities		(15,000	)		(12,400	)
Proceeds from sale of available for sale securities		15,000			12,400
Increase in other investments		(18,421	)		(9,648	)
Electric plant additions		(21,295	)		(89,831	)
Net Cash Used for Investing Activities		(39,716	)		(96,364	)
Financing Activities:
Debt issuance costs		—			(235	)
Draws on revolving credit facility		—			349,225
Repayments on revolving credit facility		—			(416,425	)
Net Cash Used for Financing Activities		—			(67,435	)
Net Change in Cash and Cash Equivalents		125,823			42,665
Cash and Cash Equivalents - Beginning of Period		9,288			27,699
Cash and Cash Equivalents - End of Period	$	135,111		$	70,364

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

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OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. 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 September 30, 2021, our consolidated results of operations for the three and nine months ended September 30, 2021 and 2020, and cash flows for the nine months ended September 30, 2021 and 2020.  The consolidated results of operations for the three and nine months ended September 30, 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 2 classes of members.  Our 11 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 2 representatives from each of the member distribution cooperatives and 1 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 September 30, 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 ongoing 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.

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The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2021 and December 31, 2020: 

			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	September 30,		Assets		Inputs		Inputs
	2021		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust (1)	$	89,433	$	89,433	$	0	$	—
Nuclear decommissioning trust - net asset value (1)(2)		173,607		0		0		—
Unrestricted investments and other (3)		179		0		179		—
Derivatives - gas and power (4)		101,107		81,988		13,777		5,342
Total Financial Assets	$	364,326	$	171,421	$	13,956	$	5,342
Derivatives - gas and power (4)	$	1,619	$	—	$	1,619	$	—
Total Financial Liabilities	$	1,619	$	—	$	1,619	$	—

			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	$	0	$	—
Nuclear decommissioning trust - net asset value (1)(2)		166,300		0		0		—
Unrestricted investments and other (3)		166		0		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 (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.

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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.

As of September 30, 2021, we recorded $61.9 million of obligations to return cash collateral, which is recorded in other liabilities on our Condensed Consolidated Balance Sheet.

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

		Quantity
		As of September 30,		As of December 31,
Commodity	Unit of Measure	2021		2020
Natural gas	MMBTU		62,880,000		55,630,000
Purchased power - financial transmission rights	MWh		9,955,656		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 September 30,		As of December 31,
	Balance Sheet Location	2021		2020
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	95,765	$	2,062
Financial transmission rights	Other assets		5,342		1,416
Total derivatives in an asset position		$	101,107	$	3,478
Derivatives in a liability position:
Natural gas futures contracts	Other liabilities	$	1,619	$	6,406
Total derivatives in a liability position		$	1,619	$	6,406

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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, 2021 and 2020

	Amount of Gain				Location of	Amount of Gain (Loss) Reclassified
	(Loss) Recognized				Gain (Loss)	from Regulatory Asset/Liability
	in Regulatory				Reclassified	into Income for the
Derivatives	Asset/Liability for				from Regulatory	Three Months					Nine Months
Accounted for Utilizing	Derivatives as of				Asset/Liability	Ended					Ended
Regulatory Accounting	September 30,				into Income	September 30,					September 30,
	2021		2020			2021		2020			2021		2020
	(in thousands)					(in thousands)
Natural gas futures contracts	$	100,595	$	9,090	Fuel	$	17,466	$	(6,621	)	$	14,433	$	(33,813	)
Purchased power		5,342		1,164	Purchased power		179		3,192			4,630		(1,291	)
Total	$	105,937	$	10,254		$	17,645	$	(3,429	)	$	19,063	$	(35,104	)

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.

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4. Investments

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

			Gross		Gross
			Unrealized		Unrealized			Fair		Carrying
Description	Cost		Gains		Losses			Value		Value
	(in thousands)
September 30, 2021
Nuclear decommissioning trust (1)
Debt securities	$	84,175	$	4,727	$	—		$	88,902	$	88,902
Equity securities		91,730		83,135		(1,258	)		173,607		173,607
Cash and other		531		—		—			531		531
Total Nuclear Decommissioning Trust	$	176,436	$	87,862	$	(1,258	)	$	263,040	$	263,040
Other
Equity securities	$	132	$	47	$	—		$	179	$	179
Non-marketable equity investments		2,146		2,443		—			4,589		2,146
Total Other	$	2,278	$	2,490	$	—		$	4,768	$	2,325
										$	265,365
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 September 30, 2021, were as follows:

Description	Less than 1 year		1-5 years		5-10 years		More than 10 years		Total
	(in thousands)
Other (1)	$	—	$	—	$	88,902	$	—	$	88,902
Total	$	—	$	—	$	88,902	$	—	$	88,902

⁽¹⁾ The contractual maturities of other debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust.

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5. 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 September 30, 2021 and December 31, 2020, we had 0 borrowings and had a $0.5 million letter of credit outstanding under this facility.

Revenue Recognition

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

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, 2021 and 2020, we had 0 sales to TEC and TEC had 0 sales to third parties.    

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

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Energy revenues	$	89,124	$	106,417	$	250,178	$	285,710
Renewable energy credits		9		13		26		26
Demand revenues		96,187		95,203		292,564		303,938
Total revenues from sales to member distribution cooperatives		185,320		201,633		542,768		589,674
Non-members:
Energy revenues		9,726		9,314		22,315		19,456
Renewable energy credits		5,921		5,334		8,485		5,438
Demand revenues		—		—		—		21
Total revenues from sales to non-members		15,647		14,648		30,800		24,915
Total operating revenues	$	200,967	$	216,281	$	573,568	$	614,589

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,

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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 and currently do not anticipate a material impact from adopting this standard.

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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 ongoing 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 September 30, 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 and nine months ended September 30, 2021, as compared to the same periods in 2020, were primarily impacted by the decrease in our total energy rate to our member distribution cooperatives and changes in purchased power expense, and for the nine months ended September 30, 2021, the increase in operations and maintenance expense and differences in weather.  

• Total revenues from sales to our member distribution cooperatives decreased 8.1% and 8.0%, for the three and nine months ended September 30, 2021, respectively, as compared to the same periods in 2020.  Energy revenues decreased 16.3% and 12.4%, respectively, primarily due to the 15.9% decrease in our total energy rate to our member distribution cooperatives effective January 1, 2021.  For the nine months ended September 30, 2021, the decrease was partially offset by the 4.1% increase in energy sales in MWh to our member distribution cooperatives.  The weather for the nine months ended September 30, 2020, was mild, and the weather for the nine months ended September 30, 2021, was more typical and contributed to the increase in energy sales in MWh to our member distribution cooperatives.  

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• Purchased power expense, which includes the cost of purchased energy and capacity, increased 20.4% for the three months ended September 30, 2021, primarily due to the 18.2% increase in purchased energy costs.  Purchased energy costs increased as a result of the 45.9% increase in the average cost of purchased energy, partially offset by the 19.0% decrease in the volume of purchased energy.  Purchased power expense decreased 13.3% for the nine months ended September 30, 2021.  Purchased energy costs decreased 8.7% as a result of the 8.8% decrease in the average cost of purchased energy.  Purchased capacity costs decreased 50.8% due to the decrease in costs to meet our PJM capacity obligation.

• Operations and maintenance expense increased 24.9%, for the nine months ended September 30, 2021, primarily due to costs related to emissions allowances and scheduled outages at our owned facilities.

Our financial condition as of September 30, 2021, was primarily impacted by the increase in the fair value of derivatives related to natural gas which contributed to increases in cash and cash equivalents, other assets, regulatory liabilities, and other liabilities.

We believe our results for the three and nine months ended September 30, 2021, were not materially impacted by the COVID-19 pandemic.  We believe that other factors described above, such as the decrease in our total energy rate to our member distribution cooperatives, changes in purchased power expense, and the impact of weather, were the primary drivers of our results for the three and nine months ended September 30, 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%.  

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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 and nine months ended September 30, 2021 and 2020.

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands)
Margin Stabilization adjustment	$	6,407	$	13,438	$	15,277	$	6,431

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 and nine months ended September 30, 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.  

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Our total revenues decreased $15.3 million, or 7.1%, and $41.0 million, or 6.7%, respectively, as compared to the same periods 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 half of 2021 as compared to the mild weather in the first half of 2020.

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 sell excess power and renewable energy credits to non-members at prevailing market prices as control is transferred.  Energy sales in MWh to our member distribution cooperatives were relatively flat and increased 4.1%, as compared to the same periods in the prior year.  We believe a significant portion of the increase relates to differences in 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.  

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 September 30, 2021, prepayments totaled $32.6 million, and extensions totaled $5.8 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, 2021, we had no borrowings outstanding under our revolving credit facility and had a cash and cash equivalents balance of $135.1 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.  

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 ongoing impact of 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.  

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Weather

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

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

The heating and cooling degree days for the three and nine months ended September 30, 2021, were as follows:

	Three Months Ended September 30,								Nine Months Ended September 30,
	2021		2020		Change				2021		2020		Change
Heating degree days		—		—		—		%		2,084		1,714		21.6	%
Cooling degree days		1,041		1,076		(3.3	)			1,347		1,361		(1.0	)

Power Supply Resources

We provide power to our members through a combination of our interests in Wildcat Point, a natural gas-fired combined cycle generation facility; North Anna, a nuclear power station; Clover, a coal-fired generation facility; two natural gas-fired combustion turbine facilities (Louisa and Marsh Run); diesel-fired distributed generation facilities; and physically-delivered forward power purchase contracts and spot market energy purchases.  Our energy supply resources for the three and nine months ended September 30, 2021 and 2020, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(in MWh and percentages)
Generated:
Wildcat Point	1,264,518	38.2	%	840,561	24.5	%	2,417,340	26.0	%	2,336,129	25.3	%
North Anna	461,757	14.0		434,328	12.7		1,287,046	13.9		1,384,719	15.0
Clover	190,386	5.7		353,645	10.3		407,694	4.4		487,126	5.3
Louisa	130,108	3.9		198,015	5.8		328,757	3.5		245,949	2.7
Marsh Run	224,678	6.8		319,951	9.4		462,010	5.0		403,827	4.4
Distributed Generation	1,542	—		1,623	—		2,665	0.0		2,266	—
Total Generated	2,272,989	68.6		2,148,123	62.7		4,905,512	52.8		4,860,016	52.7
Purchased:
Other than renewable:
Long-term and short-term	323,409	9.8		450,507	13.1		1,953,978	21.1		1,860,704	20.1
Spot market	584,288	17.7		711,202	20.7		1,888,712	20.4		1,955,875	21.2
Total Other than renewable	907,697	27.5		1,161,709	33.8		3,842,690	41.5		3,816,579	41.3
Renewable (1)	128,958	3.9		118,465	3.5		529,712	5.7		553,300	6.0
Total Purchased	1,036,655	31.4		1,280,174	37.3		4,372,402	47.2		4,369,879	47.3
Total Available Energy	3,309,644	100.0	%	3,428,297	100.0	%	9,277,914	100.0	%	9,229,895	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.

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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 and nine months ended September 30, 2021 and 2020, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Wildcat Point		99.6	%		96.3	%		87.6	%		90.7	%
North Anna		95.4			90.2			88.7			94.8
Clover		88.3			83.0			82.2			66.6
Louisa		91.1			98.0			93.4			96.3
Marsh Run		97.5			100.0			96.0			95.5

Capacity Factor

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
Wildcat Point		58.5	%		38.6	%		37.5	%		36.1	%
North Anna		95.3			89.6			89.6			95.9
Clover		20.6			37.7			14.7			17.4

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.  

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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 and nine months ended September 30, 2021 and 2020, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2021		2020		2021		2020
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Energy revenues	$	89,124	$	106,417	$	250,178	$	285,710
Renewable energy credits		9		13		26		26
Demand revenues		96,187		95,203		292,564		303,938
Total revenues from sales to member distribution cooperatives		185,320		201,633		542,768		589,674
Non-members:
Energy revenues		9,726		9,314		22,315		19,456
Renewable energy credits		5,921		5,334		8,485		5,438
Demand revenues		—		—		—		21
Total revenues from sales to non-members		15,647		14,648		30,800		24,915
Total operating revenues	$	200,967	$	216,281	$	573,568	$	614,589
Energy sales to:	(in MWh)
Member distribution cooperatives		3,078,335		3,092,128		8,640,410		8,301,242
Non-members		207,281		329,464		575,859		881,605
Total energy sales		3,285,616		3,421,592		9,216,269		9,182,847
Average cost of energy to member distribution cooperatives (per MWh)	$	28.95	$	34.42	$	28.95	$	34.42
Average total cost to member distribution cooperatives (per MWh)	$	60.20	$	65.21	$	62.82	$	71.03

Member Distribution Cooperatives

For the three and nine months ended September 30, 2021, total revenues from sales to our member distribution cooperatives decreased $16.3 million, or 8.1%, and $46.9 million, or 8.0%, respectively, as compared to the same periods in 2020.  Energy revenues decreased $17.3 million, or 16.3%, and $35.5 million, or 12.4%, respectively, primarily due to the 15.9% decrease in our total energy rate, effective January 1, 2021, and for the nine months ended September 30, 2021, the decrease was partially offset by the 4.1% increase in energy sales in MWh.  The weather for the nine months ended September 30, 2020, was mild, and the weather for the nine months ended September 30, 2021, was more typical and contributed to the increase in energy sales in MWh to our member distribution cooperatives.  Demand revenues were relatively flat for the three months ended September 30, 2021, and decreased $11.4 million, or 3.7%, for the nine months ended September 30, 2021, primarily 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	)

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Operating Expenses

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2021			2020		2021			2020
	(in thousands)
Fuel	$	46,953		$	45,893	$	113,141		$	111,277
Purchased power		57,471			47,721		174,142			200,756
Transmission		33,257			31,815		97,125			98,737
Deferred energy		(2,008	)		25,691		(12,903	)		8,648
Operations and maintenance		17,571			16,490		58,126			46,524
Administrative and general		10,572			10,653		32,092			32,817
Depreciation and amortization		17,594			17,423		52,825			52,447
Amortization of regulatory asset/(liability), net		11,494			7,895		15,707			7,044
Accretion of asset retirement obligations		1,417			1,366		4,247			4,096
Taxes, other than income taxes		2,279			2,281		7,173			7,130
Total Operating Expenses	$	196,600		$	207,228	$	541,675		$	569,476

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 $10.6 million, or 5.1%, and $27.8 million, or 4.9%, for the three and nine months ended September 30, 2021, respectively, as compared to the same periods in 2020.  The decrease for the three months ended September 30, 2021, was primarily as a result of the decrease in deferred energy expense, partially offset by the increase in purchased power expense.  The decrease for the nine months ended September 30, 2021, was primarily as the result of decreases in purchased power expense and deferred energy expense, partially offset by the increase in operations and maintenance expense.

• Purchased power expense, which includes the cost of purchased energy and capacity, increased $9.8 million, or 20.4%, for the three months ended September 30, 2021, primarily due to the $8.1 million, or 18.2%, increase in purchased energy costs.  Purchased energy costs increased as a result of the 45.9% increase in the average cost of purchased energy, partially offset by the 19.0% decrease in the volume of purchased energy.   Purchased power expense decreased $26.6 million, or 13.3%, for the nine months ended September 30, 2021.  Purchased energy costs decreased $15.6 million, or 8.7%, as a result of the 8.8% decrease in the average cost of purchased energy. Purchased capacity costs decreased $11.0 million, or 50.8%, 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, decreased $27.7 million and $21.6 million, for the three and nine months ended September 30, 2021, respectively.  For the three and nine months ended September 30, 2021, we under-collected $2.0 million and $12.9 million, respectively.  For the three and nine months ended September 30, 2020, we over-collected $25.7 million and $8.6 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.

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• Operations and maintenance expense increased $11.6 million, or 24.9%, for the nine months ended September 30, 2021, primarily due to costs related to emissions allowances and scheduled outages at our owned facilities.  The increase in emissions allowances was primarily due to our additional purchases of allowances to comply with state law following Virginia joining the Regional Greenhouse Gas Initiative in 2021.

Other Items

Interest Charges, Net

The primary factors affecting our interest charges, net are issuances of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility, and capitalized interest.  The major components of interest charges, net for the three and nine months ended September 30, 2021 and 2020, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2021			2020			2021			2020
	(in thousands)
Interest on long-term debt	$	(13,980	)	$	(14,507	)	$	(41,942	)	$	(43,508	)
Interest on revolving credit facility		(97	)		(280	)		(303	)		(1,964	)
Other interest		(98	)		(193	)		(274	)		(699	)
Total interest charges		(14,175	)		(14,980	)		(42,519	)		(46,171	)
Allowance for borrowed funds used during construction		224			135			624			334
Interest charges, net	$	(13,951	)	$	(14,845	)	$	(41,895	)	$	(45,837	)

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 and nine months ended September 30, 2021, as compared to the same periods in 2020.

Financial Condition

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

• Regulatory liabilities increased $122.0 million primarily due to the increase in the fair value of derivatives related to natural gas.

• Other assets increased $100.1 million primarily due to the increase in the fair value of derivatives related to natural gas.

• Other liabilities increased $57.9 million primarily due to the decrease in the NYMEX margin account for derivatives related to natural gas.

• Nuclear decommissioning trust increased $20.7 million due to the increase in the market value of our investments.

• Accrued expenses increased $16.6 million due to accrued interest on long-term debt and accrued property taxes.

• Accounts payable–members decreased $22.6 million due to the $24.6 million decrease in member prepayments and the $2.0 million increase in the amounts owed to our member distribution cooperatives under Margin Stabilization.  

• Accounts receivable–members decreased $15.6 million due to the $14.9 million decrease in wholesale power invoices for September 2021 as compared to December 2020 and the $0.7 million decrease in member distribution cooperatives’ extended payment balances.

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• Deferred energy decreased $12.9 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 $10.2 million as of December 31, 2020, and September 30, 2021, respectively.

Liquidity and Capital Resources

Sources

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

Operations

During the first nine months of 2021 and 2020, our operating activities provided cash flows of $165.5 million and $206.5 million, respectively.  Operating activities in 2021 were primarily impacted by the $127.3 million change in regulatory assets and liabilities, the $42.2 million change in deferred charges and other assets and deferred credits and other liabilities, the $17.0 million change in current assets, and the $12.9 million change in deferred energy.

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

Financings

We fund the portion of our capital expenditures that we are not able to fund from operations through borrowings under our revolving credit facility and issuances of debt in the capital markets.  These capital expenditures consist primarily of the costs related to the development, construction, acquisition, 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 third 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

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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.

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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 were held on October 28, 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 5.  OTHER INFORMATION

On November 9, 2021, we received notice from Mr. Michael J. Keyser, in connection with his resignation from BARC Electric Cooperative to become the Chief Executive Officer of the National Renewables Cooperative Organization, that he will resign from our board of directors, effective December 10, 2021.  

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ITEM 6.  EXHIBITS

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

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	OLD DOMINION ELECTRIC COOPERATIVE
		Registrant
Date: November 10, 2021		/s/ BRYAN  S. ROGERS
		Bryan S. Rogers
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)

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