Old Dominion Electric Cooperative 10Q 2020 Q3 Quarterly report

Old Dominion Electric Cooperative 10-Q2020 Q3 Quarterly report

Content analysis

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, 2020

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

For the transition period from to

Commission file number 000-50039

OLD DOMINION ELECTRIC COOPERATIVE

(Exact name of registrant as specified in its charter)

VIRGINIA

23-7048405

(State or other jurisdiction of

incorporation or organization)

(I.R.S. employer

identification no.)

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

(804) 747-0592

(Registrant’s telephone number, including area code)

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the Registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒

Securities registered pursuant to Section 12(b) of the Act: NONE

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

GLOSSARY OF TERMS

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

Abbreviation or Acronym		Definition

ACES		Alliance for Cooperative Energy Services Power Marketing, LLC

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

OLD DOMINION ELECTRIC COOPERATIVE

INDEX

		Page Number

PART I. Financial Information

Item 1. Financial Statements

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

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

Condensed Consolidated Statements of Cash Flows (unaudited) – Nine Months Ended September 30, 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		24

PART II. Other Information		25

Item 1. Legal Proceedings		25

Item 1A. Risk Factors		25
Item 5. Other Information		26

Item 6. Exhibits		27

OLD DOMINION ELECTRIC COOPERATIVE

PART 1. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

CONDENSED CONSOLIDATED BALANCE SHEETS

	September 30, 2020			December 31, 2019
	(in thousands)
	(unaudited)
ASSETS:
Electric Plant:
Property, plant, and equipment	$	2,525,477		$	2,531,986
Less accumulated depreciation		(960,520	)		(927,065	)
Net Property, plant, and equipment		1,564,957			1,604,921
Nuclear fuel, at amortized cost		12,313			20,705
Construction work in progress		43,112			31,462
Net Electric Plant		1,620,382			1,657,088
Investments:
Nuclear decommissioning trust		217,126			211,108
Unrestricted investments and other		2,276			5,380
Total Investments		219,402			216,488
Current Assets:
Cash and cash equivalents		70,364			3,469
Restricted cash and cash equivalents		—			24,230
Accounts receivable		9,783			12,422
Accounts receivable–members		73,156			101,185
Fuel, materials, and supplies		57,928			62,083
Deferred energy		—			3,548
Prepayments and other		2,996			4,702
Total Current Assets		214,227			211,639
Deferred Charges and Other Assets:
Regulatory assets		28,818			57,742
Other assets		9,650			26,287
Total Deferred Charges and Other Assets		38,468			84,029
Total Assets	$	2,092,479		$	2,169,244
CAPITALIZATION AND LIABILITIES:
Capitalization:
Patronage capital	$	450,545		$	441,311
Non-controlling interest		5,858			5,846
Total Patronage capital and Non-controlling interest		456,403			447,157
Long-term debt		1,118,241			1,117,867
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
Current Liabilities:
Long-term debt due within one year		40,792			40,792
Accounts payable		53,341			147,916
Accounts payable–members		85,646			26,804
Accrued expenses		23,172			5,850
Deferred energy		5,100			—
Total Current Liabilities		208,051			221,362
Deferred Credits and Other Liabilities:
Asset retirement obligations		177,766			173,669
Regulatory liabilities		129,264			117,483
Other liabilities		2,754			24,506
Total Deferred Credits and Other Liabilities		309,784			315,658
Commitments and Contingencies		—			—
Total Capitalization and Liabilities	$	2,092,479		$	2,169,244

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF REVENUES,

EXPENSES, AND PATRONAGE CAPITAL (UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(in thousands)
Operating Revenues	$	216,281		$	252,729		$	614,589		$	708,493
Operating Expenses:
Fuel		45,893			51,000			111,277			143,921
Purchased power		47,721			83,851			200,756			238,828
Transmission		31,815			38,107			98,737			121,476
Deferred energy		25,691			15,403			8,648			17,855
Operations and maintenance		16,490			23,721			46,524			59,638
Administrative and general		10,653			11,358			32,817			38,395
Depreciation and amortization		17,423			17,207			52,447			51,539
Amortization of regulatory asset/(liability), net		7,895			(9,163	)		7,044			(26,342	)
Accretion of asset retirement obligations		1,366			1,386			4,096			4,154
Taxes, other than income taxes		2,281			2,350			7,130			7,185
Total Operating Expenses		207,228			235,220			569,476			656,649
Operating Margin		9,053			17,509			45,113			51,844
Other income (expense), net		(18	)		(41	)		(78	)		(43	)
Investment income		8,800			1,358			10,052			5,369
Interest charges, net		(14,845	)		(15,648	)		(45,837	)		(47,519	)
Income taxes		2			(4	)		(4	)		(19	)
Net Margin including Non-controlling interest		2,992			3,174			9,246			9,632
Non-controlling interest		4			(16	)		(12	)		(54	)
Net Margin attributable to ODEC		2,996			3,158			9,234			9,578
Patronage Capital - Beginning of Period		447,549			435,083			441,311			428,663
Patronage Capital - End of Period	$	450,545		$	438,241		$	450,545		$	438,241

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

OLD DOMINION ELECTRIC COOPERATIVE

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

	Nine Months Ended September 30,
	2020				2019
	(in thousands)
Operating Activities:
Net Margin including Non-controlling interest	$	9,246			$	9,632
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization		52,447				51,539
Other non-cash charges		12,864				12,674
Change in current assets		36,529				(11,806	)
Change in deferred energy		8,648				17,855
Change in current liabilities		47,286				18,063
Change in regulatory assets and liabilities		44,330				(38,127	)
Change in other assets and other liabilities		(4,886	)			(3,225	)
Net Cash Provided by Operating Activities		206,464				56,605
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	)
Electric plant additions		(89,831	)			(28,747	)
Net Cash Used for Investing Activities		(96,364	)			(32,613	)
Financing Activities:
Debt issuance costs		(235	)			(257	)
Draws on revolving credit facility		349,225				167,250
Repayments on revolving credit facility		(416,425	)			(167,250	)
Net Cash Used for Financing Activities		(67,435	)			(257	)
Net Change in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents		42,665				23,735
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - Beginning of Period		27,699				22,978
Cash and Cash Equivalents and Restricted Cash and Cash Equivalents - End of Period	$	70,364			$	46,713

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

OLD DOMINION ELECTRIC COOPERATIVE

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

General

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. In the opinion of management, the accompanying unaudited condensed consolidated financial statements contain all adjustments, which include only normal recurring adjustments, necessary for a fair statement of our consolidated financial position as of September 30, 2020, our consolidated results of operations for the three and nine months ended September 30, 2020 and 2019, and cash flows for the nine months ended September 30, 2020 and 2019. The consolidated results of operations for the three and nine months ended September 30, 2020, 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 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 and December 31, 2019, respectively. 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 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. 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.

We did not have any other comprehensive income for the periods presented.

2.	Fair Value Measurements

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall in different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of September 30, 2020 and December 31, 2019:

			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	September 30,		Assets		Inputs		Inputs
	2020		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾	$	81,118	$	81,118	$	—	$	—
Nuclear decommissioning trust - net asset value ⁽¹⁾⁽²⁾		136,008		—		—		—
Unrestricted investments and other ⁽³⁾		132		—		132		—
Derivatives - gas and power ⁽⁴⁾		13,274		10,931		1,179		1,164
Total Financial Assets	$	230,532	$	92,049	$	1,311	$	1,164

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

			Quoted Prices
			in Active		Significant
			Markets for		Other		Significant
			Identical		Observable		Unobservable
	December 31,		Assets		Inputs		Inputs
	2019		(Level 1)		(Level 2)		(Level 3)
	(in thousands)
Nuclear decommissioning trust ⁽¹⁾	$	64,504	$	64,504	$	—	$	—
Nuclear decommissioning trust - net asset value ⁽¹⁾⁽²⁾		146,604		—		—		—
Unrestricted investments and other ⁽³⁾		126		—		126		—
Derivatives - gas and power ⁽⁴⁾		1,013		—		—		1,013
Total Financial Assets	$	212,247	$	64,504	$	126	$	1,013

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

⁽¹⁾

For additional information about our nuclear decommissioning trust, see Note 4—Investments below.

⁽²⁾

Nuclear decommissioning trust includes investments measured at net asset value per share (or its equivalent) as a practical expedient and these investments have not been categorized in the fair value hierarchy. The fair value amounts presented in this table are intended to permit reconciliation of the fair value hierarchy to the amounts presented in our Condensed Consolidated Balance Sheet.

⁽³⁾

Unrestricted investments and other includes investments that are related to equity securities.

⁽⁴⁾

Derivatives - gas and power represent natural gas futures contracts and call option premiums (Level 1 and Level 2), and financial transmission rights (Level 3). Level 1 are indexed against NYMEX. Level 2 are valued by ACES using observable market inputs for similar transactions. Level 3 are valued by ACES using unobservable market inputs, including situations where there is little market activity. Sensitivity in the market price of financial transmission rights could impact the fair value. For additional information about our derivative financial instruments, see Note 1 of the Notes to Consolidated Financial Statements in our 2019 Annual Report on Form 10-K.

3.	Derivatives and Hedging

We are exposed to market price risk by purchasing power to supply the power requirements of our member distribution cooperatives that are not met by our owned generation. In addition, the purchase of fuel to operate our generating facilities also exposes us to market price risk. To manage this exposure, we utilize derivative instruments. See Note 1 of the Notes to Consolidated Financial Statements in our 2019 Annual Report on Form 10-K.

Changes in the fair value of our derivative instruments accounted for at fair value are recorded as a regulatory asset or regulatory liability. The change in these accounts is included in the operating activities section of our Condensed Consolidated Statements of Cash Flows.

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


		Quantity
		As of September 30,		As of December 31,
Commodity	Unit of Measure	2020		2019
Natural gas	MMBTU		57,190,000		73,560,000
Purchased power - financial transmission rights	MWh		4,860,209		5,771,291

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	2020		2019
		(in thousands)
Derivatives in an asset position:
Natural gas futures contracts	Other assets	$	12,110	$	—
Financial transmission rights	Other assets		1,164		1,013
Total derivatives in an asset position		$	13,274	$	1,013

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

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, 2020 and 2019



	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,
	2020		2019				2020			2019			2020			2019
	(in thousands)						(in thousands)
Natural gas futures contracts	$	9,090	$	(13,603	)	Fuel	$	(6,621	)	$	(5,175	)	$	(33,813	)	$	(15,081	)
Purchased power		1,164		1,053		Purchased power		3,192			3,334			(1,291	)		(2,068	)
Total	$	10,254	$	(12,550	)		$	(3,429	)	$	(1,841	)	$	(35,104	)	$	(17,149	)

Our hedging activities expose us to credit-related risks. We use hedging instruments, including forwards, futures, financial transmission rights, and options, to mitigate our power market price risks. Because we rely substantially on the use of hedging instruments, we are exposed to the risk that counterparties will default in performance of their obligations to us. Although we assess the creditworthiness of counterparties and other credit issues related to these hedging instruments, and we may require our counterparties to post collateral with us, defaults may still occur. Defaults may take the form of failure to physically deliver purchased energy or failure to pay. If a default occurs, we may be forced to enter into alternative contractual arrangements or purchase energy in the forward, short-term, or spot markets at then-current market prices that may exceed the prices previously agreed upon with the defaulting counterparty.

4.	Investments

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

			Gross		Gross
			Unrealized		Unrealized			Fair		Carrying
Description	Cost		Gains		Losses			Value		Value
	(in thousands)
September 30, 2020
Nuclear decommissioning trust ⁽¹⁾
Debt securities	$	60,809	$	7,656	$	—		$	68,465	$	68,465
Equity securities		81,662		59,375		(5,030	)		136,007		136,007
Cash and other ⁽²⁾		12,654		—		—			12,654		12,654
Total Nuclear Decommissioning Trust	$	155,125	$	67,031	$	(5,030	)	$	217,126	$	217,126

Other
Equity securities	$	111	$	21	$	—		$	132	$	132
Non-marketable equity investments		2,144		2,403		—			4,547		2,144
Total Other	$	2,255	$	2,424	$	—		$	4,679	$	2,276
										$	219,402

December 31, 2019
Nuclear decommissioning trust ⁽¹⁾
Debt securities	$	59,748	$	4,325	$	—		$	64,073	$	64,073
Equity securities		85,303		63,858		(2,557	)		146,604		146,604
Cash and other		431		—		—			431		431
Total Nuclear Decommissioning Trust	$	145,482	$	68,183	$	(2,557	)	$	211,108	$	211,108

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
Non-marketable equity investments		2,146		2,176		—			4,322		2,146
Total Other	$	2,256	$	2,191	$	—		$	4,447	$	2,271
										$	216,488

⁽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 2019 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.

⁽²⁾

Cash and other includes funds related to the rebalancing of equity securities which will be invested in equity and debt securities in the fourth quarter of 2020.

Contractual maturities of debt securities as of September 30, 2020, were as follows:


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

⁽¹⁾

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

Other

Wildcat Point Generation Facility

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.

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, 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 outstanding under this facility and a $0.5 million letter of credit.

Cash and Cash Equivalents

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

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

	As of September 30,
	2020		2019
	(in thousands)
Cash and cash equivalents	$	70,364	$	22,583
Restricted cash and cash equivalents		—		24,130
Total	$	70,364	$	46,713

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

Revenue Recognition

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

We sell excess purchased and generated energy to PJM, TEC, or third parties. Sales to TEC consist of sales of excess energy that we do not need to meet the actual needs of our member distribution cooperatives. TEC’s sales to third parties are reflected as non-member revenues. For the three and nine months ended September 30, 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, 2020 and 2019, were as follows:

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

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

Total operating revenues	$	216,281	$	252,729	$	614,589	$	708,493

Virginia CO₂ Regulation

On April 12, 2020, the governor of Virginia signed legislation that requires that all investor-owned utility generating facilities that emit CO₂ 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 CO₂Regulation, see “Regulation—Virginia CO₂Regulation” in Part 1, Item 1 Business of our 2019 Annual Report on Form 10-K.

6.	New Accounting Pronouncements

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.

OLD DOMINION ELECTRIC COOPERATIVE

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS

OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Caution Regarding Forward-looking Statements

Management’s Discussion and Analysis of Financial Condition and Results of Operations contains forward-looking statements regarding matters that could have an impact on our business, financial condition, and future operations. These statements, based on our expectations and estimates, are not guarantees of future performance and are subject to risks, uncertainties, and other factors. These risks, uncertainties, and other factors include, but are not limited to, general business conditions, demand for energy, federal and state legislative and regulatory actions and legal and administrative proceedings, changes in and compliance with environmental laws and policies, general credit and capital market conditions, weather conditions, the cost of commodities used in our industry, 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.

Critical Accounting Policies

As of September 30, 2020, there have been no significant changes in our critical accounting policies as disclosed in our 2019 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, 2020, were primarily impacted by the decreases in our total energy rate and PJM’s economic dispatch of our generating facilities, and milder weather.

•

Total revenues from sales to our member distribution cooperatives decreased 15.2% and 13.1% for the three and nine months ended September 30, 2020, respectively, as compared to the same periods in 2019, primarily as a result of the 17.1% and 20.1% decrease in energy revenues, respectively. The decrease in energy revenues was primarily due to the 16.2% decrease in the average cost of energy for the three and nine months ended September 30, 2020. Additionally, milder weather contributed to the 1.1% and 4.6% decrease in energy sales in MWh to our member distribution cooperatives, respectively.

•

Generation from our owned facilities decreased 7.6% and 17.8%, respectively, primarily due to PJM’s economic dispatch of our generating facilities. The decrease in generation contributed to the 10.0% and 22.7% decrease in fuel expense, respectively.

•

Purchased power expense, which includes the cost of purchased energy and capacity, decreased 43.1% and 15.9%, respectively, primarily due to the decrease in purchased energy expense. Purchased energy expense decreased 38.6% and 15.3%, respectively, due to the decrease in the average cost of purchased energy, partially offset by the 8.1% and 19.9% increase in the volume of purchased energy, respectively, primarily as a result of decreased generation from our owned facilities.

We believe our results for the three and nine months ended September 30, 2020, 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 in our total energy rate and the impact of milder weather, were the primary drivers of our results for the three and nine months ended September 30, 2020. We continue to closely monitor how the outbreak will affect our operations, results of operations, financial condition, and cash flows, and have taken certain actions as a result of the pandemic. See “Factors Affecting Results—COVID-19 Pandemic” below for a more detailed discussion.

Factors Affecting Results

Formula Rate

Our power sales are comprised of two power products – energy and demand. Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as demand.

The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula rate accepted by FERC, which is intended to permit collection of revenues which will equal the sum of:

•

all of our costs and expenses;

•

20% of our total interest charges (margin requirement); and

•

additional equity contributions approved by our board of directors.

The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval.

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

Demand costs, which are primarily fixed costs, such as capacity costs under power purchase contracts with third parties, transmission expense, administrative and general expense, 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, 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 requirements, 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 up 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, and for the nine months ended September 30, 2019; and to increase revenues for the three months ended September 30, 2019.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2020		2019			2020		2019
	(in thousands)
Margin Stabilization adjustment	$	13,438	$	(110	)	$	6,431	$	5,413

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 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, 2020, we do not believe there was a material impact attributable to the COVID-19 pandemic on our results of operations or financial condition.

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

4.6%, respectively, as compared to the same periods in the prior year. We believe a portion of the decrease relates to weather. 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 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, prepayments totaled $79.2 million and extensions totaled $10.4 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, we had no borrowings outstanding under our revolving credit facility and had a cash and cash equivalents balance of $70.4 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. Additionally, 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.

In July 2020, the Commonwealth of Virginia issued the Emergency Temporary Standard Infectious Disease Prevention: SARS-CoV-2 Virus That Causes COVID-19 regulation. All employers covered by this regulation must comply with mandatory requirements to protect employees from workplace exposure to COVID-19, and we are subject to this regulation for our operations located in Virginia. We do not anticipate that compliance under this regulation will result in a material impact on our operations or costs.

Ongoing Considerations

We are continuing to monitor ways in which the COVID-19 pandemic could affect our operations, results of operations, financial condition, and cash flows. The extent to which the pandemic will impact us is uncertain and will depend on numerous evolving factors that we may not be able to accurately predict, including the duration and scope of the pandemic and the actions taken in response. See “Part II Other Information—Item 1A. Risk Factors.”

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, 2020 and 2019, were as follows:

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

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, 2020 and 2019, were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
	(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	%
North Anna	434,328	12.7		424,494	12.1		1,384,719	15.0		1,281,276	13.4
Clover	353,645	10.3		274,847	7.8		487,126	5.3		422,084	4.4
Louisa	198,015	5.8		237,004	6.8		245,949	2.7		392,469	4.1
Marsh Run	319,951	9.4		317,257	9.0		403,827	4.4		614,806	6.5
Distributed Generation	1,623	—		1,324	—		2,266	—		2,086	—
Total Generated	2,148,123	62.7		2,324,156	66.2		4,860,016	52.7		5,915,613	61.9
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
Spot market	711,202	20.7		454,739	13.0		1,955,875	21.2		1,464,187	15.3
Total Other than renewable	1,161,709	33.8		1,065,660	30.4		3,816,579	41.3		3,101,529	32.4
Renewable ⁽¹⁾	118,465	3.5		118,886	3.4		553,300	6.0		542,672	5.7
Total Purchased	1,280,174	37.3		1,184,546	33.8		4,369,879	47.3		3,644,201	38.1
Total Available Energy	3,428,297	100.0	%	3,508,702	100.0	%	9,229,895	100.0	%	9,559,814	100.0	%

⁽¹⁾

Related to our contracts from renewable facilities from which we obtain renewable energy credits. We sell these renewable energy credits to our member distribution cooperatives and non-members.

Generating Facilities

Our operating expenses, and consequently our rates to our member distribution cooperatives, are significantly affected by the operations of our generating facilities, which are under dispatch control of PJM. For further discussion of PJM, see “Business—Power Supply Resources—PJM” in Item 1 of our 2019 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, 2020 and 2019, was as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	2020			2019			2020			2019
Wildcat Point		96.3	%		84.2	%		90.7	%		85.6	%
North Anna		90.2			87.5			94.8			88.4
Clover		83.0			68.5			66.6			63.0
Louisa		98.0			94.7			96.3			94.3
Marsh Run		100.0			99.3			95.5			97.2

Capacity Factor

The output of Wildcat Point, North Anna, and Clover for the three and nine months ended September 30, 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,
	2020			2019			2020			2019
Wildcat Point		38.6	%		50.1	%		36.1	%		51.4	%
North Anna		89.6			87.6			95.9			89.1
Clover		37.7			29.2			17.4			15.2

Sale of Rock Springs Combustion Turbine Facility

On September 14, 2018, we sold our interest in Rock Springs and related assets to EPRS for $115 million. Prior to the sale, we 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.

Sales to Member Distribution Cooperatives

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

Sales to Non-members

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

Results of Operations

Operating Revenues

Our operating revenues are derived from sales of power and renewable energy credits to our member distribution cooperatives and non-members. Our operating revenues and energy sales in MWh by type of purchaser for the three and nine months ended September 30, 2020 and 2019, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Revenues from sales to:
Member distribution cooperatives
Energy revenues	$	106,417	$	128,418	$	285,710	$	357,552
Renewable energy credits		13		4		26		21
Demand revenues		95,203		109,243		303,938		321,237
Total revenues from sales to member distribution cooperatives		201,633		237,665		589,674		678,810
Non-members:
Energy revenues		9,314		11,812		19,456	��	24,955
Renewable energy credits		5,334		3,252		5,438		4,672
Demand revenues		—		—		21		56
Total revenues from sales to non-members		14,648		15,064		24,915		29,683
Total operating revenues	$	216,281	$	252,729	$	614,589	$	708,493

Energy sales to:	(in MWh)
Member distribution cooperatives		3,092,128		3,125,704		8,301,242		8,703,657
Non-members		329,464		367,463		881,605		802,902
Total energy sales		3,421,592		3,493,167		9,182,847		9,506,559

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

Member Distribution Cooperatives

For the three and nine months ended September 30, 2020, total revenues from sales to our member distribution cooperatives decreased $36.0 million, or 15.2%, and $89.1 million, or 13.1%, respectively, as compared to the same periods in 2019. Energy revenues decreased $22.0 million, or 17.1%, and $71.8 million, or 20.1%, respectively, primarily due to the 16.2% decrease in the average cost of energy for the three and nine months ended September 30, 2020. Additionally, energy sales in MWh to our member distribution cooperatives decreased 1.1% and 4.6%, respectively. Demand revenues decreased $14.0 million, or 12.9%, and $17.3 million, or 5.4%, respectively, primarily due to decreases 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.

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, 2019		(1.3	)
January 1, 2020		(16.2	)

Operating Expenses

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2020		2019			2020		2019
	(in thousands)
Fuel	$	45,893	$	51,000		$	111,277	$	143,921
Purchased power		47,721		83,851			200,756		238,828
Transmission		31,815		38,107			98,737		121,476
Deferred energy		25,691		15,403			8,648		17,855
Operations and maintenance		16,490		23,721			46,524		59,638
Administrative and general		10,653		11,358			32,817		38,395
Depreciation and amortization		17,423		17,207			52,447		51,539
Amortization of regulatory asset/(liability), net		7,895		(9,163	)		7,044		(26,342	)
Accretion of asset retirement obligations		1,366		1,386			4,096		4,154
Taxes, other than income taxes		2,281		2,350			7,130		7,185
Total Operating Expenses	$	207,228	$	235,220		$	569,476	$	656,649

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 million, or 11.9%, and $87.2 million, or 13.3%, for the three and nine months ended September 30, 2020, respectively, as compared to the same periods in 2019, primarily as a result of decreases 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.

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Fuel expense decreased $5.1 million, or 10.0%, and $32.6 million, or 22.7%, respectively, primarily due to the 7.6% and 17.8% decrease in generation from our owned facilities, respectively, primarily due to PJM’s economic dispatch.

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Purchased power expense, which includes the cost of purchased energy and capacity, decreased $36.1 million, or 43.1%, and $38.1 million, or 15.9%, respectively, primarily due to the decrease in purchased energy expense. Purchased energy expense decreased $28.2 million, or 38.6%, and $32.3 million, or 15.3%, respectively, due to the decrease in the average cost of purchased energy, partially offset by the 8.1% and 19.9% increase in the volume of purchased energy, respectively, primarily as a result of decreased generation from our owned facilities. The decrease in the average cost of purchased energy was partially due to the expiration of a long-term purchased power contract on May 31, 2020, which was replaced by lower cost purchased energy.

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Transmission expense decreased $6.3 million, or 16.5%, and $22.7 million, or 18.7%, respectively, due to changes in PJM charges for network transmission services.

•

Operations and maintenance expense decreased $7.2 million, or 30.5%, and $13.1 million, or 22.0%, respectively, primarily due to the difference in the timing and scope of scheduled outages in 2020 as compared to 2019.

•

Deferred energy expense, which represents the difference between energy revenues and energy expenses, increased $10.3 million for the three months ended September 30, 2020, and decreased $9.2 million for the nine months ended September 30, 2020. For the three months ended September 30, 2020 and 2019, we over-collected $25.7 million and $15.4 million, respectively. For the nine months ended September 30, 2020 and 2019, we over-collected $8.6 million and $17.9 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 2019 Annual Report on Form 10-K.

•

Amortization of regulatory asset/(liability), net increased $17.1 million and $33.4 million, respectively. For the three and nine months ended September 30, 2019, we amortized $9.4 million and $28.3 million of the gain on the sale of Rock Springs and related assets, respectively. See “Factors Affecting Results—Generating Facilities—Sale of Rock Springs Combustion Turbine Facility.”

Other Items

Interest Charges, Net

The primary factors affecting our interest charges, net are issuance of indebtedness, scheduled payments of principal on our indebtedness, interest charges related to our revolving credit facility, and capitalized interest. The major components of interest charges, net for the three and nine months ended September 30, 2020 and 2019, were as follows:

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

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, 2020, as compared to the same periods in 2019.

Financial Condition

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

•

Accounts payable decreased $94.6 million due to the decrease in construction-related payables primarily as a result of the Wildcat Point settlement and power purchase payables.

•

Revolving credit facility decreased $67.2 million due to repayment of outstanding borrowings under this facility.

•

Regulatory assets decreased $28.9 million primarily due to the change in the deferred net unrealized losses on derivative instruments.

•

Accounts receivable–members decreased $28.0 million due to the $17.9 million decrease in wholesale power invoices for September 2020 as compared to December 2019 and the $10.1 million decrease in member distribution cooperatives’ extended payment balances.

•

Other liabilities decreased $21.8 million due to the increase in the fair value of our natural gas hedges.

•

Other assets decreased $16.6 million due to decreases in the collateral requirements of our natural gas hedges partially offset by the increase in the fair value of our natural gas hedges.

•

Accounts payable–members increased $58.8 million due to the $63.9 million increase in member prepayments partially offset by the $4.3 million patronage capital retirement.

•

Accrued expenses increased $17.3 million due to accrued interest on long-term debt and accrued property taxes.

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. 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.

Operations

During the first nine months of 2020 and 2019, our operating activities provided cash flows of $206.5 million and $56.6 million, respectively. Operating activities in 2020 were primarily impacted by the $47.3 million change in current liabilities, the $44.3 million change in regulatory assets and liabilities, and the $36.5 million change in current assets.

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 through 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, 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 outstanding under this facility and a $0.5 million letter of credit.

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 financings 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.

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 2020.

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

OLD DOMINION ELECTRIC COOPERATIVE

PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

Recovery of Costs from PJM

In 2014, we filed a petition at FERC seeking recovery from PJM of 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, 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. 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 recovery as a separate breach of an oral contract claim in the Circuit Court for the County of Henrico in the Commonwealth of Virginia. 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 believ es will not have a material adverse impact on our results of operations or financial condition, there is no other litigation pending or threatened against us.

ITEM 1A. RISK FACTORS

Our 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 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

Virginia CO₂ Regulation

ITEM 6. EXHIBITS


31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a)
31.2		Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a)
32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. § 1350
32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. § 1350
101.INS		XBRL Instance Document
101.SCH		XBRL Taxonomy Extension Schema Document
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document
101.LAB		XBRL Taxonomy Extension Label Linkbase Document
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

SIGNATURE

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


	OLD DOMINION ELECTRIC COOPERATIVE
		Registrant

Date: November 10, 2020		/s/ BRYAN S. ROGERS
		Bryan S. Rogers
		Senior Vice President and Chief Financial Officer
		(Principal financial officer)

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Emerging growth company