Document And Entity Information
Document And Entity Information | 12 Months Ended |
Dec. 31, 2022 USD ($) shares | |
Cover [Abstract] | |
Document Type | 10-K |
Amendment Flag | false |
Document Period End Date | Dec. 31, 2022 |
Document Fiscal Year Focus | 2022 |
Document Fiscal Period Focus | FY |
Entity Registrant Name | OLD DOMINION ELECTRIC COOPERATIVE |
Entity Central Index Key | 0000885568 |
Current Fiscal Year End Date | --12-31 |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | shares | 0 |
Entity Well-known Seasoned Issuer | No |
Entity Public Float | $ | $ 0 |
Entity Current Reporting Status | No |
Entity Voluntary Filers | Yes |
Entity Shell Company | false |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Entity Interactive Data Current | Yes |
Entity File Number | 000-50039 |
Entity Incorporation, State or Country Code | VA |
Entity Tax Identification Number | 23-7048405 |
Entity Address, Address Line One | 4201 Dominion Boulevard |
Entity Address, City or Town | Glen Allen |
Entity Address, State or Province | VA |
Entity Address, Postal Zip Code | 23060 |
City Area Code | (804) |
Local Phone Number | 747-0592 |
Document Annual Report | true |
Document Transition Report | false |
ICFR Auditor Attestation Flag | false |
Documents Incorporated by Reference | NONE |
Auditor Firm ID | 42 |
Auditor Name | Ernst & Young LLP |
Auditor Location | Richmond, Virginia |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Electric Plant: | ||
Property, plant, and equipment | $ 2,549,435 | $ 2,542,407 |
Less accumulated depreciation | (1,116,531) | (1,049,756) |
Net Property, plant, and equipment | 1,432,904 | 1,492,651 |
Nuclear fuel, at amortized cost | 19,155 | 14,495 |
Construction work in progress | 56,075 | 48,956 |
Net Electric Plant | 1,508,134 | 1,556,102 |
Investments: | ||
Nuclear decommissioning trust | 225,263 | 276,658 |
Unrestricted investments and other | 2,437 | 2,361 |
Total Investments | 227,700 | 279,019 |
Current Assets: | ||
Cash and cash equivalents | 15,213 | 107,852 |
Accounts receivable | 36,573 | 13,821 |
Accounts receivable–members | 111,838 | 63,037 |
Fuel, materials, and supplies | 100,964 | 61,808 |
Deferred energy | 83,836 | 5,005 |
Prepayments and other | 19,391 | 10,757 |
Total Current Assets | 367,815 | 262,280 |
Deferred Charges and Other Assets: | ||
Regulatory assets | 37,249 | 22,253 |
Other assets | 64,081 | 55,405 |
Total Deferred Charges and Other Assets | 101,330 | 77,658 |
Total Assets | 2,204,979 | 2,175,059 |
CAPITALIZATION AND LIABILITIES: | ||
Patronage capital | 476,082 | 464,777 |
Non-controlling interest | 6,296 | 5,831 |
Total Patronage capital and Non-controlling interest | 482,378 | 470,608 |
Long-term debt | 972,167 | 1,020,759 |
Revolving credit facility | 50,000 | |
Total Long-term debt and Revolving credit facility | 1,022,167 | 1,020,759 |
Total Capitalization | 1,504,545 | 1,491,367 |
Current Liabilities: | ||
Long-term debt due within one year | 49,041 | 49,041 |
Accounts payable | 167,601 | 82,988 |
Accounts payable–members | 108,729 | 112,742 |
Accrued expenses | 5,967 | 6,128 |
Total Current Liabilities | 331,338 | 250,899 |
Deferred Credits and Other Liabilities: | ||
Asset retirement obligations | 190,670 | 184,797 |
Regulatory liabilities | 161,953 | 220,619 |
Other liabilities | 16,473 | 27,377 |
Total Deferred Credits and Other Liabilities | 369,096 | 432,793 |
Total Capitalization and Liabilities | $ 2,204,979 | $ 2,175,059 |
Consolidated Statements Of Reve
Consolidated Statements Of Revenues, Expenses, And Patronage Capital - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Income Statement [Abstract] | |||
Operating Revenues | $ 1,005,917 | $ 780,640 | $ 807,704 |
Revenue, Product and Service [Extensible Enumeration] | us-gaap:ElectricityMember | us-gaap:ElectricityMember | us-gaap:ElectricityMember |
Operating Expenses: | |||
Fuel | $ 193,599 | $ 166,517 | $ 144,348 |
Purchased power | 462,526 | 234,471 | 250,546 |
Transmission | 151,778 | 131,290 | 128,427 |
Deferred energy | (78,831) | (28,116) | 26,660 |
Operations and maintenance | 91,360 | 78,294 | 61,518 |
Administrative and general | 42,111 | 41,372 | 43,023 |
Depreciation and amortization | 69,167 | 70,416 | 69,902 |
Amortization of regulatory asset/(liability), net | (960) | 16,458 | 9,069 |
Accretion of asset retirement obligations | 5,873 | 5,664 | 5,463 |
Taxes, other than income taxes | 8,784 | 9,171 | 9,275 |
Total Operating Expenses | 945,407 | 725,537 | 748,231 |
Operating Margin | 60,510 | 55,103 | 59,473 |
Other income (expense), net | 1,967 | 409 | (105) |
Investment income | 4,709 | 20,162 | 13,106 |
Interest charges, net | (55,265) | (55,657) | (60,306) |
Income taxes (expense)/benefit | (151) | 8 | (2) |
Net Margin including Non-controlling interest | 11,770 | 20,025 | 12,166 |
Non-controlling interest | (465) | 22 | (7) |
Net Margin attributable to ODEC | 11,305 | 20,047 | 12,159 |
Patronage Capital - Beginning of Period | 464,777 | 453,470 | 441,311 |
Patronage Capital - Retirement | (8,740) | ||
Patronage Capital - End of Period | $ 476,082 | $ 464,777 | $ 453,470 |
Consolidated Statements Of Cash
Consolidated Statements Of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Operating Activities: | |||
Net Margin including Non-controlling interest | $ 11,770 | $ 20,025 | $ 12,166 |
Adjustments to reconcile net margin to net cash provided by operating activities: | |||
Depreciation and amortization | 69,167 | 70,416 | 69,902 |
Other non-cash charges | 16,192 | 16,886 | 17,121 |
Change in current assets | (119,343) | 14,170 | 16,799 |
Change in deferred energy | (78,831) | (28,117) | 26,660 |
Change in current liabilities | 80,459 | 56,303 | 23,284 |
Change in regulatory assets and liabilities | (19,453) | 72,527 | 33,157 |
Change in deferred charges and other assets and deferred credits and other liabilities | (19,567) | (24,619) | (1,432) |
Net Cash (Used for) Provided by Operating Activities | (59,606) | 197,591 | 197,657 |
Investing Activities: | |||
Purchases of held to maturity securities | (80,012) | ||
Proceeds from sale of held to maturity securities | 80,600 | 3,115 | |
Purchases of available for sale securities | (15,000) | (24,800) | |
Proceeds from sale of available for sale securities | 15,000 | 24,800 | |
Increase in other investments | (3,491) | (20,105) | (12,561) |
Electric plant additions | (31,089) | (29,881) | (98,395) |
Net Cash Used for Investing Activities | (33,992) | (49,986) | (107,841) |
Financing Activities: | |||
Debt issuance costs | (235) | ||
Payments of long-term debt | (49,041) | (49,041) | (40,792) |
Draws on revolving credit facility | 152,500 | 355,225 | |
Repayments on revolving credit facility | (102,500) | (422,425) | |
Net Cash Provided by (Used for) Financing Activities | 959 | (49,041) | (108,227) |
Net Change in Cash and Cash Equivalents | (92,639) | 98,564 | (18,411) |
Cash and Cash Equivalents - Beginning of Period | 107,852 | 9,288 | 27,699 |
Cash and Cash Equivalents - End of Period | $ 15,213 | $ 107,852 | $ 9,288 |
Summary Of Significant Accounti
Summary Of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Summary Of Significant Accounting Policies | NOTE 1—Summary of Significant Accounting Policies General The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and 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 $ 12.7 million and $ 5.8 million, respectively, as of December 31, 2022 and December 31, 2021 . The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC, which is a taxable corporation. As TEC is 100 % owned by our Class A members, its equity is presented as a non-controlling interest on our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities for which we have significant influence is recorded using the equity method of accounting. We have a power sales contract with TEC under which we may sell to TEC, power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. During 2022, we sold excess power to TEC, and TEC had sales to third parties. In 2021 and 2020, we had no sales to TEC and TEC had no sales to third parties. Additionally, we have a separate contract under which we may purchase natural gas from TEC; however, we have not purchased natural gas from TEC in recent years. TEC does not engage in speculative trading. 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 customers located in Virginia, Delaware, and Maryland. Our sole Class B member is TEC. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. 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 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 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. Electric Plant Electric plant is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, an allowance for borrowed funds used during construction, and asset retirement costs. Upon the partial sale or retirement of plant assets, the original asset cost and current disposal costs less sale proceeds, if any, are charged or credited to accumulated depreciation. In accordance with industry practice, no profit or loss is recognized in connection with normal sales and retirements of property units. Maintenance and repair costs are expensed as incurred. Replacements and renewals of items considered to be units of property are capitalized to the property accounts. Depreciation We use the group method of depreciation and periodically conduct depreciation studies and update rates, if necessary. Our depreciation rates for the past three years were as follows: Depreciation Rates Generating Facility 2022 2021 2020 Wildcat Point 3.1 % 3.1 % 3.1 % North Anna 3.3 3.3 3.3 Clover 1.9 1.9 1.9 Louisa 3.1 3.1 3.1 Marsh Run 3.0 3.0 3.0 Nuclear Fuel Nuclear fuel is amortized on a unit of production basis sufficient to fully amortize the cost of fuel over its estimated service life and is recorded in fuel expense. Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us that it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices, which are dependent upon the market environment. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels. Under the Nuclear Waste Policy Act of 1982, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract with Virginia Power. As a result, Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred and in 2012 signed a settlement agreement with the DOE. By mutual agreement of the parties, the settlement agreement is extendable to provide for resolution of damages. In November 2022, the DOE provided notification that it intends to extend the settlement agreement to provide for periodic payments for damages incurred through December 31, 2025, and future additional extensions are contemplated by the settlement agreement. We continue to recognize receivables for certain spent nuclear fuel-related costs. We believe the recovery of these costs from the DOE is probable. As of December 31, 2022 and 2021 , we had an outstanding receivable of $ 1.9 million and $ 2.4 million, respectively. Fuel, Materials, and Supplies Fuel, materials, and supplies is primarily composed of fuel and spare parts for our generating assets, renewable energy credits, and emission allowances, all of which are recorded at cost. Fuel consists primarily of coal and No. 2 fuel oil. Allowance for Borrowed Funds Used During Construction Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2022, 2021, and 2020 , was $ 1.3 million, $ 0.9 million, and $ 0.5 million, respectively. Income Taxes We are a not-for-profit wholesale power supply cooperative and currently are exempt from federal income taxation under IRC Section 501(c)(12). In order to maintain our tax-exempt status, we must receive at least 85 % of our income from our members on an annual basis. We maintained our tax-exempt status as of December 31, 2022. TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2022, 2021, and 2020 . Operating Revenues Our operating revenues are derived from sales of power and renewable energy credits to our members 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. See Note 5—Wholesale Power Contracts. We transfer control of the electricity over time and our member distribution cooperatives simultaneously receive and consume the benefits of the electricity. The amount we invoice our member distribution cooperatives on a monthly basis corresponds directly to the value to the member distribution cooperatives of our performance, which is determined by our formula rate included in the wholesale power contract. We sell excess energy and renewable energy credits to non-members at prevailing market prices as control is transferred. ODEC sells excess purchased and generated energy not needed to meet the actual needs of our member distribution cooperatives to PJM, TEC, or other counterparties. Our financial statements represent the consolidated financial statements of ODEC and TEC and through the consolidation process, all intercompany balances and transactions have been eliminated and TEC’s sales are reflected as non-member revenues. Our operating revenues by type of purchaser for the past three years were as follows: Year Ended December 31, 2022 2021 2020 (in thousands) Revenues from sales to: Member distribution cooperatives Energy revenues $ 540,423 $ 328,045 $ 375,714 Renewable energy credits 259 36 33 Demand revenues 410,437 398,819 395,067 Total revenues from sales to member distribution cooperatives 951,119 726,900 770,814 Non-members Energy revenues (1) 42,818 45,255 31,431 Renewable energy credits 11,980 8,485 5,438 Demand revenues — — 21 Total revenues from sales to non-members 54,798 53,740 36,890 Total operating revenues $ 1,005,917 $ 780,640 $ 807,704 (1) Includes TEC’s sales to non-members of $ 29.4 million for the year ended December 31, 2022. TEC did no t have sales to non-members in 2021 or 2020. Formula Rate Our power sales are comprised of two power products – energy and demand. Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as demand. The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula rate accepted by FERC, which is intended to permit collection of revenues which will equal the sum of: • all of our costs and expenses; • 20% of our total interest charges (margin requirement); and • additional equity contributions approved by our board of directors. The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval. Energy costs, which are primarily variable costs, such as natural gas, nuclear, and coal fuel costs, and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate (collectively referred to as the total energy rate). The base energy rate is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to zero. We can revise the energy adjustment rate during the year if it becomes apparent that the total energy rate is over-collecting or under-collecting our actual and anticipated energy costs. Any revision to the energy adjustment rate requires board approval and that the resulting change to the total energy rate is at least 2 %. Demand costs, which are primarily fixed costs, such as capacity costs under power purchase contracts with third parties, transmission costs, administrative and general expenses, depreciation expense, interest expense, margin requirement, and additional equity contributions approved by our board of directors, are recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. We collect our total demand costs through the following three separate rates: • transmission service rate – designed to collect transmission-related and distribution-related costs; • RTO capacity service rate – designed to collect capacity costs in PJM that PJM allocates to ODEC and 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. See “Margin Stabilization” 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. Margin Stabilization Margin Stabilization allows us to review our actual demand-related costs of service and demand revenues and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. Our formula rate allows us to collect and return amounts utilizing Margin Stabilization. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year. We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, generally in the succeeding calendar year. We adjust operating revenues and accounts receivable–members or accounts payable–members, as appropriate, to reflect these adjustments. These adjustments are treated as due, owed, incurred, and accrued for the year to which the adjustment relates. The following table details the reduction in revenues utilizing Margin Stabilization for the past three years: Year Ended December 31, 2022 2021 2020 (in thousands) Margin Stabilization adjustment $ 2,255 $ 11,614 $ 13,227 Member Power Bill Payment Plan We maintain a program which allows our member distribution cooperatives to prepay or extend payment on their monthly power bills. Under this program, we pay interest on prepayment balances at a blended investment and short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and short-term borrowing rate. Amounts prepaid by our member distribution cooperatives are included in accounts payable–members and as of December 31, 2022 and 2021 , were $ 105.8 million and $ 92.3 million, respectively. Amounts extended to our member distribution cooperatives are included in accounts receivable–members and as of December 31, 2022 , were $ 8.9 million. As of December 31, 2021, there were no amounts extended. Regulatory Assets and Liabilities We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations. This allows certain of our revenues and expenses to be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be collected or returned through our formula rate in future periods. Regulatory assets represent costs that we expect to collect from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory assets are generally included in deferred charges and other assets and regulatory liabilities are generally included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or a regulatory liability, is included in current assets or current liabilities, respectively. See “Deferred Energy” below. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their recovery through rates. Debt Issuance Costs Capitalized costs associated with the issuance of long-term debt totaled $ 4.8 million and $ 5.2 million as of December 31, 2022 and 2021 , respectively, and are included as a direct reduction to long-term debt. Capitalized costs associated with our revolving credit facility totaled $ 0.3 million and $ 0.6 million as of December 31, 2022 and 2021 , respectively, and are recorded in other assets. These costs are being amortized using the effective interest method over the life of the respective long-term debt issuances and revolving credit facility, and are included in interest charges, net. Deferred Energy In accordance with Accounting for Regulated Operations, we use the deferral method of accounting to recognize differences between our energy revenues collected from our member distribution cooperatives and our energy expenses. The deferred energy balance represents the net accumulation of any under- or over-collection of energy costs. Under-collected energy costs appear as an asset and will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Conversely, over-collected energy costs appear as a liability and will be returned to our member distribution cooperatives in subsequent periods through our formula rate. As of December 31, 2022 and 2021, we had an under-collected deferred energy balance of $ 83.8 million and $ 5.0 million, respectively. The following table summarizes the changes to our total energy rate since 2020, which were implemented to address the differences in our realized as well as projected energy costs: Effective Date of Rate Change % Change January 1, 2020 ( 16.2 ) January 1, 2021 ( 15.9 ) January 1, 2022 20.3 May 1, 2022 6.7 July 1, 2022 47.7 January 1, 2023 ( 1.5 ) Financial Instruments (including Derivatives) Investments included in the nuclear decommissioning trust are carried at fair value. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or a regulatory asset, respectively, until realized. Unrestricted investments in debt securities that we have the positive intent and ability to hold to maturity are recorded at amortized cost. Non-marketable equity investments, which are accounted for under the equity method, are included in other investments and recorded at cost. Equity securities in other investments are recorded at fair value. See Note 8—Investments. We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for our facilities which utilize natural gas. These derivatives do not qualify for the normal purchases/normal sales accounting exception. For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we defer all remaining gains and losses on a net basis as a regulatory liability or regulatory asset, respectively, in accordance with Accounting for Regulated Operations. See "Regulatory Assets and Liabilities” above. These amounts are subsequently reclassified as purchased power or fuel expense as the power or fuel is delivered and/or the contract settles. Generally, derivatives are reported at fair value in other assets and other liabilities. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. Patronage Capital We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members based upon their respective power purchases in accordance with our bylaws. Any distributions of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our Indenture. See Note 10—Long-term Debt for discussion of the restrictions contained in the Indenture. We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity approved by our board of directors. Revenues in excess of expenses in any year are designated as net margin attributable to ODEC on our Consolidated Statements of Revenues, Expenses, and Patronage Capital. We designate retained net margins attributable to ODEC on our Consolidated Balance Sheet as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us. On December 14, 2021, our board of directors approved an additional equity contribution of $ 8.7 million, and subsequently declared a patronage capital retirement of $ 8.7 million. As a result of the December 14, 2021 declaration, we reduced patronage capital and increased accounts payable–members by $ 8.7 million. The $ 8.7 million patronage capital retirement was paid on March 25, 2022 . Concentrations of Credit Risk Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, derivatives, and receivables arising from sales to our members and non-members. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives as reflected by accounts receivable–members were $ 111.8 million and $ 63.0 million, as of December 31, 2022 and 2021 , respectively. Segment We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Our President and CEO serves as our chief decision-maker who manages and reviews our operating results as one operating, and therefore one reportable, segment. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, physically-delivered forward power purchase contracts, and spot market energy purchases. Cash and Cash Equivalents For purposes of our 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. 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 LIBOR 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. In December 2022, the FASB issued ASU 2022-06 Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. These standards did not have a material impact on our financial statements. |
Electric Plant
Electric Plant | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
Electric Plant | NOTE 2—Electric Plant Our net electric plant was composed of the following as of December 31, 2022: Wildcat North Clover Combustion Other Total (in thousands) Property, plant, and equipment $ 879,319 $ 418,073 $ 708,240 $ 441,000 $ 102,803 $ 2,549,435 Accumulated depreciation ( 125,832 ) ( 272,036 ) ( 427,304 ) ( 254,425 ) ( 36,934 ) ( 1,116,531 ) Net Property, plant, and equipment 753,487 146,037 280,936 186,575 65,869 1,432,904 Nuclear fuel, at amortized cost — 19,155 — — — 19,155 Construction work in progress 245 47,378 159 227 8,066 56,075 Net Electric Plant $ 753,732 $ 212,570 $ 281,095 $ 186,802 $ 73,935 $ 1,508,134 Our net electric plant was composed of the following as of December 31, 2021: Wildcat North Clover Combustion Other Total (in thousands) Property, plant, and equipment $ 877,789 $ 416,259 $ 707,333 $ 440,168 $ 100,858 $ 2,542,407 Accumulated depreciation ( 98,726 ) ( 260,491 ) ( 414,647 ) ( 241,051 ) ( 34,841 ) ( 1,049,756 ) Net Property, plant, and equipment 779,063 155,768 292,686 199,117 66,017 1,492,651 Nuclear fuel, at amortized cost — 14,495 — — — 14,495 Construction work in progress 7 41,312 1,311 51 6,275 48,956 Net Electric Plant $ 779,070 $ 211,575 $ 293,997 $ 199,168 $ 72,292 $ 1,556,102 Wildcat Point We own Wildcat Point, a 980 MW (net capacity entitlement) natural gas-fueled combined cycle generation facility. Wildcat Point achieved commercial operation on April 17, 2018. North Anna We hold an 11.6 % undivided ownership interest in North Anna, a two -unit, 1,892 MW (net capacity entitlement) nuclear power facility operated by Virginia Power, which owns the balance of the plant. We are responsible for and must fund 11.6 % of all post-acquisition date additions and operating costs associated with North Anna, as well as a pro-rata portion of Virginia Power’s administrative and general expenses directly attributable to North Anna. Our portion of assets, liabilities, and operating expenses associated with North Anna are included on our consolidated financial statements in accordance with proportionate consolidation accounting. As of December 31, 2022 and 2021 , we had an outstanding accounts payable balance of $ 5.6 million and $ 7.9 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at North Anna. Clover We hold a 50 % undivided ownership interest in Clover, a two -unit, 877 MW (net capacity entitlement) coal-fired electric generation facility operated by Virginia Power, which owns the balance of the plant. We are responsible for and must fund half of all additions and operating costs associated with Clover, as well as half of Virginia Power’s administrative and general expenses directly attributable to Clover. Our portion of assets, liabilities, and operating expenses associated with Clover are included on our consolidated financial statements in accordance with proportionate consolidation accounting. As of December 31, 2022 and 2021 , we had an outstanding accounts payable balance of $ 6.0 million and $ 5.5 million, respectively, due to Virginia Power for operation, maintenance, and capital investment at Clover. Combustion Turbine Facilities We own two combustion turbine facilities, Louisa and Marsh Run, that are primarily fueled by natural gas. Other We also own six distributed generation facilities, and approximately 110 miles of transmission lines on the Virginia portion of the Delmarva Peninsula. |
Accounting For Asset Retirement
Accounting For Asset Retirement And Environmental Obligations | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Accounting For Asset Retirement And Environmental Obligations | NOTE 3—Accounting for Asset Retirement and Environmental Obligations We account for our asset retirement obligations in accordance with Accounting for Asset Retirement and Environmental Obligations. This requires that legal obligations associated with the retirement of long-lived assets be recognized at fair value when incurred and capitalized as part of the related long-lived asset. Over time, the liability is accreted to its present value each period, and the capitalized asset is depreciated over the useful life of the long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Our estimated liability could change significantly if actual costs vary from assumptions or if governmental regulations change significantly. A significant portion of our asset retirement obligations relates to our share of the future costs to decommission North Anna. At December 31, 2022 and 2021 , our share of North Anna’s nuclear decommissioning asset retirement obligation totaled $ 166.3 million and $ 161.5 million, respectively. Approximately every four years , a new decommissioning study for North Anna is performed by third-party experts. A new study was performed in 2019, and we adopted it effective December 31, 2019, which resulted in an additional layer related to the asset retirement obligation associated with North Anna. The additional layer resulted in an increase to our asset retirement cost and our asset retirement obligation of $ 37.6 million. The increase is related to costs associated with spent fuel, including the change in methodology to be utilized, as a result of the DOE delay for acceptance of spent fuel, as well as the change in the market risk premium and inflation rates utilized to calculate our costs. We are not aware of any events that have occurred since the 2019 study that would materially impact our estimate or that would have required an updated study to be performed in 2022. We are required to maintain a funded trust to satisfy our future obligation to decommission the North Anna facility. See Note 8—Investments. The following represents changes in our asset retirement obligations for the years ended December 31, 2022 and 2021 (in thousands): Asset retirement obligations as of December 31, 2020 $ 179,133 Accretion expense 5,664 Asset retirement obligations as of December 31, 2021 $ 184,797 Accretion expense 5,873 Asset retirement obligations as of December 31, 2022 $ 190,670 The cash flow estimates for North Anna’s asset retirement obligation are based upon an assumption of an additional 20 -year life extension, which will extend the life of Unit 1 to April 1, 2058, and the life of Unit 2 to August 21, 2060. Virginia Power, the co-owner of North Anna, submitted an application to the NRC in August 2020 for this additional 20 -year operating license extension for North Anna. Given the life extension, the nuclear decommissioning trust was, and currently is, estimated to be adequate to fund North Anna’s asset retirement obligation and no additional funding was, or is, currently required. We ceased collection of decommissioning expense in August 2003 with the approval of FERC. As we are not currently collecting decommissioning expense in our rates, we are deferring the difference between the earnings on the nuclear decommissioning trust and the total asset retirement obligation related depreciation and accretion expense for North Anna as part of our asset retirement obligation regulatory liability. See Note 9—Regulatory Assets and Liabilities. |
Power Purchase Agreements
Power Purchase Agreements | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Power Purchase Agreements | NOTE 4—Power Purchase Agreements In 2022, 2021, and 2020 , our owned generating facilities together furnished approximately 51.5 %, 55.6 %, and 52.0 %, respectively, of our energy requirements. The remaining needs were satisfied through purchases of power in the market through long-term and short-term physically-delivered forward power purchase contracts. We also purchased power in the spot energy market. This approach to meeting our member distribution cooperatives’ energy requirements is not without risks. To mitigate these risks, we attempt to match our energy purchases with our energy needs to reduce our spot market purchases of energy and sales of excess energy. Additionally, we utilize policies, procedures, and various hedging instruments to manage our power market price risks. These policies and procedures, developed in consultation with ACES, an energy trading and risk management company, are designed to strike an appropriate balance between minimizing costs and reducing energy cost volatility. We are required to post collateral from time to time due to changes in power prices. As of December 31, 2022 , we were required to post $ 5.6 million of collateral with counterparties and as of December 31, 2021, we were not required to post collateral. Additionally, PJM requires that we provide collateral to support our obligations in connection with certain PJM transactions. As of December 31, 2022 and 2021, we had posted $ 7.9 million and $ 5.2 million, respectively. Our purchased power expense for 2022, 2021, and 2020 was $ 462.5 million, $ 234.5 million, and $ 250.5 million, respectively. As of December 31, 2022, our power purchase obligations under the various agreements were as follows: Year Ended December 31, Capacity and Energy (in millions) 2023 $ 186.9 2024 29.0 2025 1.6 $ 217.5 |
Wholesale Power Contracts
Wholesale Power Contracts | 12 Months Ended |
Dec. 31, 2022 | |
Wholesale Power Contracts [Abstract] | |
Wholesale Power Contracts | NOTE 5—Wholesale Power Contracts Our financial relationships with our member distribution cooperatives are based primarily on our contractual arrangements for the supply of power and related transmission and ancillary services. These arrangements are set forth in our wholesale power contracts with our member distribution cooperatives that are effective until January 1, 2054, and beyond this date unless either party gives the other at least three years notice of termination. The wholesale power contracts are all-requirements contracts. Each contract obligates us to sell and deliver to a member distribution cooperative, and obligates that member distribution cooperative to purchase and receive from us, all power that it requires for the operation of its system, with limited exceptions, to the extent that we have the power and facilities available to do so. An exception to the all-requirements obligations of our member distribution cooperatives relates to the ability of our eight mainland Virginia member distribution cooperatives to purchase hydroelectric power allocated to them from SEPA, a federal power marketing administration. Purchases under this exception constituted less than 2 % of our member distribution cooperatives’ total energy requirements in 2022. There are two additional limited exceptions to the all-requirements nature of our wholesale power contracts. One exception permits each of our member distribution cooperatives, with 180 days prior written notice, to receive up to the greater of 5 % of its demand and associated energy or 5 MW of demand and associated energy from owned generation or other suppliers. The member distribution cooperative may return this load with proper notice. The other exception permits a member distribution cooperative to purchase additional power from other suppliers in limited circumstances following approval by our board of directors. As of December 31, 2022, none of our member distribution cooperatives had utilized this latter exception. If all of our member distribution cooperatives elected to fully utilize the 5% or 5 MW exception, we estimate the current impact on our load requirements would be a reduction of approximately 181 MW of demand and associated energy. As of December 31, 2022, approximately 144 MW of demand and associated energy had been removed under this provision. In May 2023, we anticipate that approximately 16 MW of load will return to us. We do not anticipate that the current or potential full utilization of this exception or the return of all removed load by our member distribution cooperatives would have a material impact on our results of operations, financial condition, or cash flows. Each member distribution cooperative is required to pay us monthly for the power we furnish under its wholesale power contract in accordance with our formula rate. See Note 1—Summary of Significant Accounting Policies—Formula Rate. More specifically, the formula rate is intended to meet all of our costs, expenses, and financial obligations associated with our ownership, operation, maintenance, repair, replacement, improvement, modification, retirement, and decommissioning of our generating plants, transmission system, or related facilities; services provided to the member distribution cooperatives; and the acquisition and transmission of power or related services, including: • payments of principal and premium, if any, and interest on all our indebtedness (other than payments resulting from the acceleration of the maturity of the indebtedness); • any additional cost or expense, imposed or permitted by any regulatory agency; and • additional amounts necessary to meet the requirement of any rate covenant with respect to coverage of principal and interest on our indebtedness contained in any indenture or contract with holders of our indebtedness. The rates established under the wholesale power contracts are designed to enable us to comply with financing, regulatory, and governmental requirements that apply to us from time to time. In accordance with the wholesale power contracts, our board of directors will review our formula rate at least every three years to determine if it reflects and recovers all costs and expenses indicated above, and if it represents the best way to allocate these costs and expenses among our member distribution cooperatives. In making this review, our board of directors will consider if the formula rate results in the proper price signals to our member distribution cooperatives. Due to changes in the energy sector generally and PJM specifically, the review of our formula rate often identifies new or changing bases for the costs we incur. We will not modify our formula rate in any manner that would result in a failure to recover all of our costs and other amounts described above. Revenues from our member distribution cooperatives for the past three years were as follows: Year Ended December 31, 2022 2021 2020 (in millions) Rappahannock Electric Cooperative $ 288.6 $ 223.3 $ 237.6 Shenandoah Valley Electric Cooperative 180.9 138.2 144.5 Delaware Electric Cooperative, Inc. 140.0 109.1 110.0 Choptank Electric Cooperative, Inc. 92.3 72.1 73.7 Southside Electric Cooperative 67.5 51.8 56.9 A&N Electric Cooperative 55.1 44.0 48.0 Mecklenburg Electric Cooperative 54.3 32.6 36.8 Prince George Electric Cooperative 25.8 20.2 22.9 Northern Neck Electric Cooperative 21.5 16.9 20.2 Community Electric Cooperative 13.9 10.5 11.0 BARC Electric Cooperative 11.2 8.2 9.2 Total $ 951.1 $ 726.9 $ 770.8 |
Fair Value Measurements
Fair Value Measurements | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
Fair Value Measurements | NOTE 6—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 December 31, 2022 and 2021: Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable December 31, Assets Inputs Inputs 2022 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 73,945 $ 73,945 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 151,318 — — — Unrestricted investments and other (3) 279 — 279 — Derivatives - gas and power (4) 59,902 27,839 20,773 11,290 Total Financial Assets $ 285,444 $ 101,784 $ 21,052 $ 11,290 Derivatives - gas and power (4) $ 8,721 $ — $ 8,721 $ — Total Financial Liabilities $ 8,721 $ — $ 8,721 $ — Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable December 31, Assets Inputs Inputs 2021 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 89,227 $ 89,227 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 187,431 — — — Unrestricted investments and other (3) 212 — 212 — Derivatives - gas and power (4) 50,793 32,078 3,705 15,010 Total Financial Assets $ 327,663 $ 121,305 $ 3,917 $ 15,010 Derivatives - gas and power (4) $ 4,291 $ — $ 4,291 $ — Total Financial Liabilities $ 4,291 $ — $ 4,291 $ — (1) For additional information about our nuclear decommissioning trust, see Note 8—Investments. (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 the 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—Summary of Significant Accounting Policies. |
Derivatives And Hedging
Derivatives And Hedging | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivatives And Hedging | NOTE 7—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—Summary of Significant Accounting Policies. 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 Consolidated Statements of Cash Flows. Outstanding derivative instruments, excluding contracts accounted for as normal purchase/normal sale, were as follows: Quantity As of As of Commodity Unit of Measure 2022 2021 Natural gas MMBTU 91,770,000 58,640,000 Purchased power - financial transmission rights MWh 8,450,239 9,156,789 The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows: Fair Value As of As of Balance Sheet Location 2022 2021 (in thousands) Derivatives in an asset position: Natural gas futures contracts Other assets $ 48,612 $ 35,783 Financial transmission rights Other assets 11,290 15,010 Total derivatives in an asset position $ 59,902 $ 50,793 Derivatives in a liability position: Natural gas futures contracts Other liabilities $ 8,721 $ 4,291 Total derivatives in a liability position $ 8,721 $ 4,291 The Effect of Derivative Instruments on the Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Years Ended December 31, 2022 and 2021 Amount of Gain Amount of Gain Location of (Loss) Reclassified (Loss) Recognized Gain (Loss) from Regulatory in Regulatory Reclassified Asset/Liability Asset/Liability for from Regulatory into Income for Derivatives Accounted for Derivatives as of Asset/Liability the Year Utilizing Regulatory Accounting December 31, into Income Ended December 31, 2022 2021 2022 2021 (in thousands) (in thousands) Natural gas futures contracts $ 37,448 $ 34,703 Fuel $ 123,256 $ 26,758 Purchased power 11,290 15,010 Purchased Power 20,901 9,463 Total $ 48,738 $ 49,713 $ 144,157 $ 36,221 |
Investments
Investments | 12 Months Ended |
Dec. 31, 2022 | |
Investments [Abstract] | |
Investments | NOTE 8—Investments Investments were as follows as of December 31, 2022 and 2021: Gross Gross Unrealized Unrealized Fair Carrying Description Cost Gains Losses Value Value (in thousands) December 31, 2022 Nuclear decommissioning trust (1) Debt securities $ 86,770 $ — $ ( 13,083 ) $ 73,687 $ 73,687 Equity securities 93,878 64,139 ( 6,699 ) 151,318 151,318 Cash and other 258 — — 258 258 Total Nuclear Decommissioning Trust $ 180,906 $ 64,139 $ ( 19,782 ) $ 225,263 $ 225,263 Other Equity securities $ 238 $ 41 $ — $ 279 $ 279 Non-marketable equity investments 2,158 2,182 — 4,340 2,158 Total Other $ 2,396 $ 2,223 $ — $ 4,619 $ 2,437 $ 227,700 December 31, 2021 Nuclear decommissioning trust (1) Debt securities $ 84,701 $ 4,052 $ — $ 88,753 $ 88,753 Equity securities 92,916 94,923 ( 408 ) 187,431 187,431 Cash and other 474 — — 474 474 Total Nuclear Decommissioning Trust $ 178,091 $ 98,975 $ ( 408 ) $ 276,658 $ 276,658 Other Equity securities $ 157 $ 55 $ — $ 212 $ 212 Non-marketable equity investments 2,149 2,370 — 4,519 2,149 Total Other $ 2,306 $ 2,425 $ — $ 4,731 $ 2,361 $ 279,019 (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—Accounting for Asset Retirement and Environmental Obligations. 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 December 31, 2022, were as follows: Less than More than Description 1 year 1-5 years 5-10 years 10 years Total (in thousands) Other (1) $ — $ — $ 73,687 $ — $ 73,687 Total $ — $ — $ 73,687 $ — $ 73,687 (1) The contractual maturities of other debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust. |
Regulatory Assets And Liabiliti
Regulatory Assets And Liabilities | 12 Months Ended |
Dec. 31, 2022 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets And Liabilities | NOTE 9—Regulatory Assets and Liabilities In accordance with Accounting for Regulated Operations, we record regulatory assets and liabilities that result from our ratemaking. Our regulatory assets and liabilities as of December 31, 2022 and 2021, were as follows: December 31, 2022 2021 (in thousands) Regulatory Assets: Unamortized losses on reacquired debt $ 787 $ 2,518 Deferred asset retirement costs 214 230 NOVEC contract termination fee 14,681 17,128 Interest rate hedge 1,461 1,604 Voluntary prepayment to NRECA Retirement Security Plan — 773 PJM capacity performance event, net 20,106 — Total Regulatory Assets $ 37,249 $ 22,253 Regulatory Assets included in Current Assets: Deferred energy $ 83,836 $ 5,005 Regulatory Liabilities: North Anna asset retirement obligation deferral $ 68,803 $ 72,226 North Anna nuclear decommissioning trust unrealized gain 44,357 98,567 Unamortized gains on reacquired debt 54 113 Deferred net unrealized gains on derivative instruments 48,739 49,713 Total Regulatory Liabilities $ 161,953 $ 220,619 The regulatory assets will be recognized as expenses concurrent with their collection through rates and the regulatory liabilities will be recognized as reductions to expenses concurrent with their return through rates. Regulatory assets included in deferred charges and other assets are detailed as follows: • Unamortized losses on reacquired debt are the costs we incurred to purchase our outstanding indebtedness prior to its scheduled retirement. These losses are amortized over the life of the original indebtedness and will be fully amortized in 2023. • Deferred asset retirement costs reflect the cumulative effect of change in accounting principle for the Clover and distributed generation facilities as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations. These costs will be fully amortized in 2034. • NOVEC contract termination fee reflects the amount allocated to the contract value of the payment to NOVEC in 2008 as part of the termination agreement. The wholesale power contract with NOVEC was scheduled to expire in 2028, thus the contract termination fee will be amortized ratably through 2028. • Interest rate hedge. To mitigate a portion of our exposure to fluctuations in long-term interest rates related to the debt we issued in 2011, we entered into an interest rate hedge. This will be amortized over the life of the 2011 debt and will be fully amortized in 2050. • Voluntary prepayment to NRECA Retirement Security Plan. In April 2013, we elected to make a voluntary prepayment of $ 7.7 million to the NRECA Retirement Security Plan, a noncontributory, defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the IRC. It is considered a multi-employer plan under accounting standards. We recorded this prepayment as a regulatory asset which was fully amortized in 2022. See Note 12—Employee Benefit Plans. • PJM capacity performance event, net. In December 2022, we incurred charges from PJM for a capacity performance event related to Winter Storm Elliott. On December 23 and 24, 2022, PJM issued two separate Performance Assessment Interval (“PAI”) events totaling approximately 23 hours. During a PAI event, owners of generating facilities, including ODEC, are subject to significant capacity performance charges if their generating facilities do not perform when called upon by PJM; and also are eligible for capacity performance bonus payments if those facilities perform in excess of their required capacity obligations. The capacity performance charges that PJM collects are redistributed to the PJM generators that are eligible for capacity performance bonus payments. During the Winter Storm Elliott PAI events, many PJM members, including ODEC, experienced forced outages and were unable to perform at times as a result of natural gas availability constraints and mechanical issues. Additionally, some PJM members, including ODEC, performed in excess of their required capacity obligations at times. As a result of the forced outages we experienced during the Winter Storm Elliott PAI events, we recorded a $ 20.1 million liability for estimated capacity performance charges and established a regulatory asset to defer these charges. We are unable to estimate the amount of the capacity performance bonus payments for which we may be eligible until PJM provides additional information and therefore have not recorded any capacity performance bonus payments at this time. These charges will be amortized ratably in 2024. Regulatory assets included in current assets are detailed as follows: • Deferred energy represents the net accumulation of under-collection of energy costs. We use the deferral method of accounting to recognize differences between our energy revenues collected from our member distribution cooperatives and our energy expenses. Under-collected deferred energy balances are collected from our member distribution cooperatives in subsequent periods. Regulatory liabilities included in deferred credits and other liabilities are detailed as follows: • North Anna asset retirement obligation deferral is the cumulative effect of change in accounting principle as a result of the adoption of Accounting for Asset Retirement and Environmental Obligations plus the deferral of subsequent activity primarily related to accretion expense offset by interest income on the nuclear decommissioning trust. • North Anna nuclear decommissioning trust unrealized gain (net of losses) reflects the unrealized gain on the investments in the nuclear decommissioning trust. • Unamortized gains on reacquired debt are the gains we recognized when we purchased our outstanding indebtedness prior to its scheduled retirement. These gains are amortized over the life of the original indebtedness and will be fully amortized in 2023. • Deferred net unrealized gains on derivative instruments will be matched and recognized in the same period the expense is incurred for the hedged item. |
Long-term Debt
Long-term Debt | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Long-term Debt | NOTE 10—Long-term Debt Long-term debt consists of the following: December 31, 2022 2021 (in thousands) $ 250,000,000 principal amount of First Mortgage Bonds, 2017 3.33 % $ 187,500 $ 200,000 $ 260,000,000 principal amount of First Mortgage Bonds, 2015 4.46 % 260,000 260,000 $ 72,000,000 principal amount of First Mortgage Bonds, 2015 4.56 % 72,000 72,000 $ 50,000,000 principal amount of First Mortgage Bonds, 2013 4.21 % 50,000 50,000 $ 50,000,000 principal amount of First Mortgage Bonds, 2013 4.36 % 50,000 50,000 $ 90,000,000 principal amount of First Mortgage Bonds, 2011 4.83 % 54,000 57,000 $ 165,000,000 principal amount of First Mortgage Bonds, 2011 5.54 % 148,500 156,750 $ 95,000,000 principal amount of First Mortgage Bonds, 2011 5.54 % 66,500 68,875 $ 250,000,000 principal amount of 2003 5.676 % 62,496 72,912 $ 300,000,000 principal amount of 2002 6.21 % 75,000 87,500 1,025,996 1,075,037 Debt issuance costs ( 4,788 ) ( 5,237 ) Current maturities ( 49,041 ) ( 49,041 ) $ 972,167 $ 1,020,759 As of December 31, 2022 and 2021 , deferred gains and losses on reacquired debt totaled a net loss of approximately $ 0.7 million and $ 2.4 million, respectively. Deferred gains and losses on reacquired debt are deferred under regulatory accounting. See Note 9—Regulatory Assets and Liabilities. Maturities of long-term debt for the next five years and thereafter are as follows: Year Ended December 31, (in thousands) 2023 $ 49,041 2024 49,041 2025 49,041 2026 49,041 2027 49,041 2028 and thereafter 780,791 $ 1,025,996 The aggregate fair value of long-term debt was $ 942.8 million and $ 1,292.5 million as of December 31, 2022 and 2021, respectively, based on current market prices. For debt issues that are not quoted on an exchange, interest rates currently available to us for issuance of debt with similar terms and remaining maturities are used to estimate fair value. All of our long-term debt is secured under our Indenture. Substantially all of our real property and tangible personal property and some of our intangible personal property are pledged as collateral under the Indenture. Under the Indenture, we may not make any distribution, including a dividend or payment or retirement of patronage capital, to our members if an event of default exists under the Indenture. Otherwise, we may make a distribution to our members if (1) after the distribution, our patronage capital as of the end of the most recent fiscal quarter would be equal to or greater than 20 % of our total long-term debt and patronage capital, or (2) all of our distributions for the year in which the distribution is to be made do not exceed 5 % of the patronage capital as of the end of the most recent fiscal year. For this purpose, patronage capital and total long-term debt do not include any earnings retained in any of our subsidiaries or affiliates or the debt of any of our subsidiaries or affiliates. Additionally, we maintain a revolving credit facility. See Note 11—Liquidity Resources. |
Liquidity Resources
Liquidity Resources | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Liquidity Resources | NOTE 11—Liquidity Resources 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 totaled $ 500 million through March 3, 2022, and $ 400 million from March 4, 2022 through February 28, 2025. We anticipate amending and restating this agreement during 2023. As of December 31, 2022, we had outstanding under this facility $ 50.0 million in borrowings at an interest rate of 5.35 %. We did no t have any borrowings outstanding under this facility as of December 31, 2021; however, the interest rate on borrowings would have been 1.1 %. As of December 31, 2022 and 2021, we had a $ 0.5 million letter of credit outstanding under this facility. Borrowings under the syndicated credit agreement that are based on Eurodollar rates bear interest at LIBOR plus a margin ranging from 0.90 % to 1.5 %, depending on our credit ratings. Borrowings not based on Eurodollar rates, including swingline borrowings, bear interest at the highest of (1) the federal funds effective rate plus 0.5 %, (2) the prime commercial lending rate of the administrative agent, and (3) the daily LIBOR for a one-month interest period plus 1.0 %, plus in each case a margin ranging from 0.0 % to 0.5 %. The syndicated credit agreement contains a provision that will result in interest rates being based upon a replacement index for LIBOR, if necessary. We are currently evaluating how the interest rate will be calculated using the replacement index. The phase-out of LIBOR is not expected to have a material adverse effect on our cost of borrowing due to the amounts typically outstanding under the syndicated credit agreement. Additionally, we are also responsible for customary unused commitment fees, an administrative agent fee, and letter of credit fees. The syndicated credit agreement contains customary conditions to borrowing or the issuance of letters of credit, representations and warranties, and covenants. This agreement obligates us to maintain a debt to capitalization ratio of no more than 0.85 to 1.00 and to maintain a margins for interest ratio of no less than 1.10 times interest charges (calculated in accordance with our Indenture). Outstanding loans under this agreement may be accelerated following, among other things: • our failure to timely pay any principal and interest due under the credit facility; • a breach by us of our representations and warranties in the credit agreement or related documents; • a breach of a covenant contained in the credit agreement, which, in some cases we are given an opportunity to cure and, in certain cases, includes a debt to capitalization financial covenant; • failure to pay, when due, other indebtedness above a specified amount; • an unsatisfied judgment above specified amounts; • bankruptcy or insolvency events relating to us; • invalidity of the credit agreement and related loan documentation or our assertion of invalidity; and • a failure by our member distribution cooperatives to pay amounts in excess of an agreed threshold owing to us beyond a specified cure period. We are in compliance with the credit agreement. |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2022 | |
Postemployment Benefits [Abstract] | |
Employee Benefit Plans | NOTE 12—Employee Benefit Plans Substantially all of our employees participate in the NRECA Retirement Security Plan, a noncontributory, defined benefit pension plan qualified under Section 401 and tax-exempt under Section 501(a) of the IRC. It is considered a multi-employer plan under accounting standards. The legal name of the plan is the NRECA Retirement Security Plan; the employer identification number is 53–0116145, and the plan number is 333. Plan information is available publicly through the annual Form 5500, including attachments. The plan year is January 1 through December 31. In total, the NRECA Retirement Security Plan was over 80 % funded on January 1, 2022 and 2021, based on the PPA funding target and PPA actuarial value of assets on those dates. The cost of the plan is funded annually by payments to NRECA to ensure that annuities in amounts established by the plan will be available to individual participants upon their retirement. In 2013, we elected to make a voluntary prepayment of $ 7.7 million to the NRECA Retirement Security Plan and recorded this payment as a regulatory asset which was fully amortized in 2022. There has been no funding improvement plan or rehabilitation plan implemented nor is one pending, and we did not pay a surcharge to the plan for 2022. We also participate in the Deferred Compensation Pension Restoration Plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the NRECA Retirement Security Plan because of the IRC limitations; participation in this plan was closed to new participants as of January 1, 2015. Our required contribution to the NRECA Retirement Security Plan and the Deferred Compensation Pension Restoration Plan totaled $ 4.0 million, $ 4.0 million, and $ 4.0 million in 2022, 2021, and 2020 , respectively. In each of these years, our contributions represented less than 5 % of the total contributions made to the plan by all participating employers. Beginning in 2019, we adopted the Executive Benefit Restoration Plan, which is intended to provide a supplemental benefit for employees who would have a reduction in their pension benefit from the NRECA Retirement Security Plan because of the IRC limitations. We have recorded a liability of $ 1.2 million in other liabilities. Pension expense, inclusive of administrative fees, was $ 5.4 million, $ 5.5 million, and $ 5.1 million for 2022, 2021, and 2020, respectively. Pension expense for 2022, 2021, and 2020 includes $ 0.8 million related to the amortization of the voluntary prepayment regulatory asset. We have a defined contribution 401(k) retirement plan and we match up to the first 2 % of each participant’s base salary. Our matching contributions were $ 0.3 million in 2022, 2021, and 2020 . |
Supplemental Cash Flows Informa
Supplemental Cash Flows Information | 12 Months Ended |
Dec. 31, 2022 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental Cash Flows Information | NOTE 13—Supplemental Cash Flows Information Cash paid for interest, net of amounts capitalized, in 2022, 2021, and 2020 , was $ 53.0 million, $ 53.3 million, and $ 57.9 million, respectively. Cash paid for income taxes was immaterial in 2022, 2021, and 2020. Accrued capital expenditures in 2022, 2021, and 2020 were $ 2.7 million, $ 2.7 million, and $ 3.8 million, respectively. |
Commitments And Contingencies
Commitments And Contingencies | 12 Months Ended |
Dec. 31, 2022 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments And Contingencies | NOTE 14—Commitments and Contingencies Environmental We are subject to federal, state, and local laws and regulations, and permits designed to both protect human health and the environment and to regulate the emission, discharge, or release of pollutants into the environment. We believe we are in material compliance with all current requirements of such environmental laws and regulations and permits. However, as with all electric utilities, the operation of our generating units could be affected by future changes in environmental laws and regulations, including new requirements. Capital expenditures and increased operating costs required to comply with any future regulations could be significant. Insurance The Price-Anderson Amendments Act of 1988 provides the public up to $ 13.7 billion of liability protection on a per site, per nuclear incident basis, via obligations required of owners of nuclear power plants, and allows for an inflationary adjustment every five years . During the third quarter of 2022, the total liability protection per nuclear incident available to all participants in the secondary financial protection program increased from $ 13.5 billion to $ 13.7 billion. This increase does not impact Virginia Power or our responsibility per active unit under the Price-Anderson Amendments Act of 1988. Owners of nuclear facilities could be assessed up to $ 138 million for each of their licensed reactors not to exceed $ 20 million per year per reactor. There is no limit to the number of incidents for which this retrospective premium can be assessed. Virginia Power, the co-owner of North Anna, is responsible for operating North Anna. Under several of the nuclear insurance policies procured by Virginia Power to which we are a party, we are subject to retrospective premium assessments in any policy year in which losses exceed the funds available to the insurance companies. As a joint owner of North Anna, we are a party to the insurance policies that Virginia Power procures to limit the risk of loss associated with a possible nuclear incident at the station, as well as policies regarding general liability and property coverage. All policies are administered by Virginia Power, which charges us for our proportionate share of the costs. Our share of the maximum retrospective premium assessments for the coverage assessments described above is estimated to be a maximum of $ 34.8 million as of December 31, 2022 . |
Summary Of Significant Accoun_2
Summary Of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
General | General The accompanying financial statements reflect the consolidated accounts of Old Dominion Electric Cooperative and 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 $ 12.7 million and $ 5.8 million, respectively, as of December 31, 2022 and December 31, 2021 . The income taxes reported on our Consolidated Statements of Revenues, Expenses, and Patronage Capital relate to the tax provision for TEC, which is a taxable corporation. As TEC is 100 % owned by our Class A members, its equity is presented as a non-controlling interest on our consolidated financial statements. Our non-controlling, 50% or less, ownership interest in other entities for which we have significant influence is recorded using the equity method of accounting. We have a power sales contract with TEC under which we may sell to TEC, power that we do not need to meet the needs of our member distribution cooperatives. TEC then sells this power to the market under market-based rate authority granted by FERC. During 2022, we sold excess power to TEC, and TEC had sales to third parties. In 2021 and 2020, we had no sales to TEC and TEC had no sales to third parties. Additionally, we have a separate contract under which we may purchase natural gas from TEC; however, we have not purchased natural gas from TEC in recent years. TEC does not engage in speculative trading. 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 customers located in Virginia, Delaware, and Maryland. Our sole Class B member is TEC. Our board of directors is composed of two representatives from each of the member distribution cooperatives and one representative from TEC. 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 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 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. |
Electric Plant | Electric Plant Electric plant is stated at original cost when first placed in service. Such cost includes contract work, direct labor and materials, allocable overhead, an allowance for borrowed funds used during construction, and asset retirement costs. Upon the partial sale or retirement of plant assets, the original asset cost and current disposal costs less sale proceeds, if any, are charged or credited to accumulated depreciation. In accordance with industry practice, no profit or loss is recognized in connection with normal sales and retirements of property units. Maintenance and repair costs are expensed as incurred. Replacements and renewals of items considered to be units of property are capitalized to the property accounts. |
Depreciation | Depreciation We use the group method of depreciation and periodically conduct depreciation studies and update rates, if necessary. Our depreciation rates for the past three years were as follows: Depreciation Rates Generating Facility 2022 2021 2020 Wildcat Point 3.1 % 3.1 % 3.1 % North Anna 3.3 3.3 3.3 Clover 1.9 1.9 1.9 Louisa 3.1 3.1 3.1 Marsh Run 3.0 3.0 3.0 |
Nuclear Fuel | Nuclear Fuel Nuclear fuel is amortized on a unit of production basis sufficient to fully amortize the cost of fuel over its estimated service life and is recorded in fuel expense. Virginia Power, as operating agent of North Anna, has the sole authority and responsibility to procure nuclear fuel for the facility. Virginia Power advises us that it primarily uses long-term contracts to support North Anna’s nuclear fuel requirements and that worldwide market conditions are continuously evaluated to ensure a range of supply options at reasonable prices, which are dependent upon the market environment. We are not a direct party to any of these procurement contracts and we do not control their terms or duration. Virginia Power advises us that current agreements, inventories, and spot market availability are expected to support North Anna’s current and planned fuel supply needs for the near term and that additional fuel is purchased as required to attempt to ensure optimal cost and inventory levels. Under the Nuclear Waste Policy Act of 1982, the DOE is required to provide for the permanent disposal of spent nuclear fuel produced by nuclear facilities, such as North Anna, in accordance with contracts executed with the DOE. The DOE did not begin accepting spent fuel in 1998 as specified in its contract with Virginia Power. As a result, Virginia Power sought reimbursement for certain spent nuclear fuel-related costs incurred and in 2012 signed a settlement agreement with the DOE. By mutual agreement of the parties, the settlement agreement is extendable to provide for resolution of damages. In November 2022, the DOE provided notification that it intends to extend the settlement agreement to provide for periodic payments for damages incurred through December 31, 2025, and future additional extensions are contemplated by the settlement agreement. We continue to recognize receivables for certain spent nuclear fuel-related costs. We believe the recovery of these costs from the DOE is probable. As of December 31, 2022 and 2021 , we had an outstanding receivable of $ 1.9 million and $ 2.4 million, respectively. |
Fuel, Materials, and Supplies | Fuel, Materials, and Supplies Fuel, materials, and supplies is primarily composed of fuel and spare parts for our generating assets, renewable energy credits, and emission allowances, all of which are recorded at cost. Fuel consists primarily of coal and No. 2 fuel oil. Regulatory Assets and Liabilities We account for certain revenues and expenses as a rate-regulated entity in accordance with Accounting for Regulated Operations. This allows certain of our revenues and expenses to be deferred at the discretion of our board of directors, which has budgetary and rate setting authority, if it is probable that these amounts will be collected or returned through our formula rate in future periods. Regulatory assets represent costs that we expect to collect from our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory liabilities represent probable future reductions in our revenues associated with amounts that we expect to return to our member distribution cooperatives based on rates approved by our board of directors in accordance with our formula rate. Regulatory assets are generally included in deferred charges and other assets and regulatory liabilities are generally included in deferred credits and other liabilities. Deferred energy, which can be either a regulatory asset or a regulatory liability, is included in current assets or current liabilities, respectively. See “Deferred Energy” below. We recognize regulatory assets and liabilities as expenses or as a reduction in expenses, respectively, concurrent with their recovery through rates. |
Allowance for Borrowed Funds Used During Construction | Allowance for Borrowed Funds Used During Construction Allowance for borrowed funds used during construction is defined as the net cost of borrowed funds used for construction purposes during the construction period and a reasonable rate on other funds when so used. We capitalize interest on borrowings for significant construction projects. Interest capitalized in 2022, 2021, and 2020 , was $ 1.3 million, $ 0.9 million, and $ 0.5 million, respectively. |
Income Taxes | Income Taxes We are a not-for-profit wholesale power supply cooperative and currently are exempt from federal income taxation under IRC Section 501(c)(12). In order to maintain our tax-exempt status, we must receive at least 85 % of our income from our members on an annual basis. We maintained our tax-exempt status as of December 31, 2022. TEC is a taxable corporation and its provision for income taxes was immaterial for the years ended December 31, 2022, 2021, and 2020 . |
Operating Revenues | Operating Revenues Our operating revenues are derived from sales of power and renewable energy credits to our members 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. See Note 5—Wholesale Power Contracts. We transfer control of the electricity over time and our member distribution cooperatives simultaneously receive and consume the benefits of the electricity. The amount we invoice our member distribution cooperatives on a monthly basis corresponds directly to the value to the member distribution cooperatives of our performance, which is determined by our formula rate included in the wholesale power contract. We sell excess energy and renewable energy credits to non-members at prevailing market prices as control is transferred. ODEC sells excess purchased and generated energy not needed to meet the actual needs of our member distribution cooperatives to PJM, TEC, or other counterparties. Our financial statements represent the consolidated financial statements of ODEC and TEC and through the consolidation process, all intercompany balances and transactions have been eliminated and TEC’s sales are reflected as non-member revenues. Our operating revenues by type of purchaser for the past three years were as follows: Year Ended December 31, 2022 2021 2020 (in thousands) Revenues from sales to: Member distribution cooperatives Energy revenues $ 540,423 $ 328,045 $ 375,714 Renewable energy credits 259 36 33 Demand revenues 410,437 398,819 395,067 Total revenues from sales to member distribution cooperatives 951,119 726,900 770,814 Non-members Energy revenues (1) 42,818 45,255 31,431 Renewable energy credits 11,980 8,485 5,438 Demand revenues — — 21 Total revenues from sales to non-members 54,798 53,740 36,890 Total operating revenues $ 1,005,917 $ 780,640 $ 807,704 (1) Includes TEC’s sales to non-members of $ 29.4 million for the year ended December 31, 2022. TEC did no t have sales to non-members in 2021 or 2020. |
Formula Rate | Formula Rate Our power sales are comprised of two power products – energy and demand. Energy is the physical electricity delivered through transmission and distribution facilities to customers. We must have sufficient committed energy available to us for delivery to our member distribution cooperatives to meet their maximum energy needs at any time, with limited exceptions. This committed available energy at any time is referred to as demand. The rates we charge our member distribution cooperatives for sales of energy and demand are determined by a formula rate accepted by FERC, which is intended to permit collection of revenues which will equal the sum of: • all of our costs and expenses; • 20% of our total interest charges (margin requirement); and • additional equity contributions approved by our board of directors. The formula rate identifies the cost components that we can collect through rates, but not the actual amounts to be collected. With limited minor exceptions, we can change our rates periodically to match the costs we have incurred and we expect to incur without seeking FERC approval. Energy costs, which are primarily variable costs, such as natural gas, nuclear, and coal fuel costs, and the energy costs under our power purchase contracts with third parties, are recovered through two separate rates, the base energy rate and the energy adjustment rate (collectively referred to as the total energy rate). The base energy rate is developed annually to collect energy costs as estimated in our budget including amounts in the deferred energy account from the prior year. As of January 1 of each year, the base energy rate is reset in accordance with our budget and the energy adjustment rate is reset to zero. We can revise the energy adjustment rate during the year if it becomes apparent that the total energy rate is over-collecting or under-collecting our actual and anticipated energy costs. Any revision to the energy adjustment rate requires board approval and that the resulting change to the total energy rate is at least 2 %. Demand costs, which are primarily fixed costs, such as capacity costs under power purchase contracts with third parties, transmission costs, administrative and general expenses, depreciation expense, interest expense, margin requirement, and additional equity contributions approved by our board of directors, are recovered through our demand rates. The formula rate allows us to change the actual demand rates we charge as our demand-related costs change, without FERC approval, with the exception of decommissioning cost, which is a fixed number in the formula rate that requires FERC approval prior to any adjustment. FERC approval is also needed to change account classifications currently in the formula or to add accounts not otherwise included in the current formula. Additionally, depreciation studies are required to be filed with FERC for its approval if they would result in a change in our depreciation rates. We collect our total demand costs through the following three separate rates: • transmission service rate – designed to collect transmission-related and distribution-related costs; • RTO capacity service rate – designed to collect capacity costs in PJM that PJM allocates to ODEC and 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. See “Margin Stabilization” 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. |
Margin Stabilization | Margin Stabilization Margin Stabilization allows us to review our actual demand-related costs of service and demand revenues and adjust revenues from our member distribution cooperatives to meet our financial coverage requirements and accumulate additional equity as approved by our board of directors. Our formula rate allows us to collect and return amounts utilizing Margin Stabilization. We record all adjustments, whether increases or decreases, in the year affected and allocate any adjustments to our member distribution cooperatives based on power sales during that year. We collect these increases from our member distribution cooperatives, or offset decreases against amounts owed by our member distribution cooperatives to us, generally in the succeeding calendar year. We adjust operating revenues and accounts receivable–members or accounts payable–members, as appropriate, to reflect these adjustments. These adjustments are treated as due, owed, incurred, and accrued for the year to which the adjustment relates. The following table details the reduction in revenues utilizing Margin Stabilization for the past three years: Year Ended December 31, 2022 2021 2020 (in thousands) Margin Stabilization adjustment $ 2,255 $ 11,614 $ 13,227 |
Member Power Bill Payment Plan | Member Power Bill Payment Plan We maintain a program which allows our member distribution cooperatives to prepay or extend payment on their monthly power bills. Under this program, we pay interest on prepayment balances at a blended investment and short-term borrowing rate, and we charge interest on extended payment balances at a blended prepayment and short-term borrowing rate. Amounts prepaid by our member distribution cooperatives are included in accounts payable–members and as of December 31, 2022 and 2021 , were $ 105.8 million and $ 92.3 million, respectively. Amounts extended to our member distribution cooperatives are included in accounts receivable–members and as of December 31, 2022 , were $ 8.9 million. As of December 31, 2021, there were no amounts extended. |
Debt Issuance Costs | Debt Issuance Costs Capitalized costs associated with the issuance of long-term debt totaled $ 4.8 million and $ 5.2 million as of December 31, 2022 and 2021 , respectively, and are included as a direct reduction to long-term debt. Capitalized costs associated with our revolving credit facility totaled $ 0.3 million and $ 0.6 million as of December 31, 2022 and 2021 , respectively, and are recorded in other assets. These costs are being amortized using the effective interest method over the life of the respective long-term debt issuances and revolving credit facility, and are included in interest charges, net. |
Deferred Energy | Deferred Energy In accordance with Accounting for Regulated Operations, we use the deferral method of accounting to recognize differences between our energy revenues collected from our member distribution cooperatives and our energy expenses. The deferred energy balance represents the net accumulation of any under- or over-collection of energy costs. Under-collected energy costs appear as an asset and will be collected from our member distribution cooperatives in subsequent periods through our formula rate. Conversely, over-collected energy costs appear as a liability and will be returned to our member distribution cooperatives in subsequent periods through our formula rate. As of December 31, 2022 and 2021, we had an under-collected deferred energy balance of $ 83.8 million and $ 5.0 million, respectively. The following table summarizes the changes to our total energy rate since 2020, which were implemented to address the differences in our realized as well as projected energy costs: Effective Date of Rate Change % Change January 1, 2020 ( 16.2 ) January 1, 2021 ( 15.9 ) January 1, 2022 20.3 May 1, 2022 6.7 July 1, 2022 47.7 January 1, 2023 ( 1.5 ) |
Financial Instruments (Including Derivatives) | Financial Instruments (including Derivatives) Investments included in the nuclear decommissioning trust are carried at fair value. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or a regulatory asset, respectively, until realized. Unrestricted investments in debt securities that we have the positive intent and ability to hold to maturity are recorded at amortized cost. Non-marketable equity investments, which are accounted for under the equity method, are included in other investments and recorded at cost. Equity securities in other investments are recorded at fair value. See Note 8—Investments. We primarily purchase power under both long-term and short-term physically-delivered forward contracts to supply power to our member distribution cooperatives. These forward purchase contracts meet the accounting definition of a derivative; however, a majority of these forward purchase derivative contracts qualify for the normal purchases/normal sales accounting exception under Accounting for Derivatives and Hedging. As a result, these contracts are not recorded at fair value. We record a liability and purchased power expense when the power under the physically-delivered forward contract is delivered. We also purchase natural gas futures generally for three years or less to hedge the price of natural gas for our facilities which utilize natural gas. These derivatives do not qualify for the normal purchases/normal sales accounting exception. For all derivative contracts that do not qualify for the normal purchases/normal sales accounting exception, we defer all remaining gains and losses on a net basis as a regulatory liability or regulatory asset, respectively, in accordance with Accounting for Regulated Operations. See "Regulatory Assets and Liabilities” above. These amounts are subsequently reclassified as purchased power or fuel expense as the power or fuel is delivered and/or the contract settles. Generally, derivatives are reported at fair value in other assets and other liabilities. The measurement of fair value is based on actively quoted market prices, if available. Otherwise, we seek indicative price information from external sources, including broker quotes and industry publications. For individual contracts, the use of differing assumptions could have a material effect on the contract’s estimated fair value. |
Patronage Capital | Patronage Capital We are organized and operate as a cooperative. Patronage capital represents our retained net margins, which have been allocated to our members based upon their respective power purchases in accordance with our bylaws. Any distributions of patronage capital are subject to the discretion of our board of directors and the restrictions contained in our Indenture. See Note 10—Long-term Debt for discussion of the restrictions contained in the Indenture. We operate on a not-for-profit basis and, accordingly, seek to generate revenues sufficient to recover our cost of service and produce margins sufficient to establish reasonable reserves, meet financial coverage requirements, and accumulate additional equity approved by our board of directors. Revenues in excess of expenses in any year are designated as net margin attributable to ODEC on our Consolidated Statements of Revenues, Expenses, and Patronage Capital. We designate retained net margins attributable to ODEC on our Consolidated Balance Sheet as patronage capital, which we assign to each of our members on the basis of its class of membership and business with us. On December 14, 2021, our board of directors approved an additional equity contribution of $ 8.7 million, and subsequently declared a patronage capital retirement of $ 8.7 million. As a result of the December 14, 2021 declaration, we reduced patronage capital and increased accounts payable–members by $ 8.7 million. The $ 8.7 million patronage capital retirement was paid on March 25, 2022 . |
Concentrations Of Credit Risk | Concentrations of Credit Risk Financial instruments that potentially subject us to concentrations of credit risk consist of cash equivalents, investments, derivatives, and receivables arising from sales to our members and non-members. Concentrations of credit risk with respect to receivables arising from sales to our member distribution cooperatives as reflected by accounts receivable–members were $ 111.8 million and $ 63.0 million, as of December 31, 2022 and 2021 , respectively. |
Segment | Segment We are organized for the purpose of supplying the power our member distribution cooperatives require to serve their customers on a cost-effective basis. Our President and CEO serves as our chief decision-maker who manages and reviews our operating results as one operating, and therefore one reportable, segment. We supply our member distribution cooperatives’ energy and demand requirements through a portfolio of resources including generating facilities, physically-delivered forward power purchase contracts, and spot market energy purchases. |
Cash and Cash Equivalents | Cash and Cash Equivalents For purposes of our 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. |
New Accounting Pronouncements | 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 LIBOR 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. In December 2022, the FASB issued ASU 2022-06 Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848, which defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024. These standards did not have a material impact on our financial statements. |
Summary Of Significant Accoun_3
Summary Of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Accounting Policies [Abstract] | |
Schedule of Depreciation Rates | Our depreciation rates for the past three years were as follows: Depreciation Rates Generating Facility 2022 2021 2020 Wildcat Point 3.1 % 3.1 % 3.1 % North Anna 3.3 3.3 3.3 Clover 1.9 1.9 1.9 Louisa 3.1 3.1 3.1 Marsh Run 3.0 3.0 3.0 |
Schedule Of Operating Revenue | Our operating revenues by type of purchaser for the past three years were as follows: Year Ended December 31, 2022 2021 2020 (in thousands) Revenues from sales to: Member distribution cooperatives Energy revenues $ 540,423 $ 328,045 $ 375,714 Renewable energy credits 259 36 33 Demand revenues 410,437 398,819 395,067 Total revenues from sales to member distribution cooperatives 951,119 726,900 770,814 Non-members Energy revenues (1) 42,818 45,255 31,431 Renewable energy credits 11,980 8,485 5,438 Demand revenues — — 21 Total revenues from sales to non-members 54,798 53,740 36,890 Total operating revenues $ 1,005,917 $ 780,640 $ 807,704 (1) Includes TEC’s sales to non-members of $ 29.4 million for the year ended December 31, 2022. TEC did no t have sales to non-members in 2021 or 2020. |
Schedule Of Reduction In Revenues Utilizing Margin Stabilization | The following table details the reduction in revenues utilizing Margin Stabilization for the past three years: Year Ended December 31, 2022 2021 2020 (in thousands) Margin Stabilization adjustment $ 2,255 $ 11,614 $ 13,227 |
Schedule Of Rate Changes Implemented To Address Under- And Over-Collection Of Energy Costs | The following table summarizes the changes to our total energy rate since 2020, which were implemented to address the differences in our realized as well as projected energy costs: Effective Date of Rate Change % Change January 1, 2020 ( 16.2 ) January 1, 2021 ( 15.9 ) January 1, 2022 20.3 May 1, 2022 6.7 July 1, 2022 47.7 January 1, 2023 ( 1.5 ) |
Electric Plant (Tables)
Electric Plant (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Property, Plant and Equipment [Abstract] | |
Schedule Of Net Electric Plant | Our net electric plant was composed of the following as of December 31, 2022: Wildcat North Clover Combustion Other Total (in thousands) Property, plant, and equipment $ 879,319 $ 418,073 $ 708,240 $ 441,000 $ 102,803 $ 2,549,435 Accumulated depreciation ( 125,832 ) ( 272,036 ) ( 427,304 ) ( 254,425 ) ( 36,934 ) ( 1,116,531 ) Net Property, plant, and equipment 753,487 146,037 280,936 186,575 65,869 1,432,904 Nuclear fuel, at amortized cost — 19,155 — — — 19,155 Construction work in progress 245 47,378 159 227 8,066 56,075 Net Electric Plant $ 753,732 $ 212,570 $ 281,095 $ 186,802 $ 73,935 $ 1,508,134 Our net electric plant was composed of the following as of December 31, 2021: Wildcat North Clover Combustion Other Total (in thousands) Property, plant, and equipment $ 877,789 $ 416,259 $ 707,333 $ 440,168 $ 100,858 $ 2,542,407 Accumulated depreciation ( 98,726 ) ( 260,491 ) ( 414,647 ) ( 241,051 ) ( 34,841 ) ( 1,049,756 ) Net Property, plant, and equipment 779,063 155,768 292,686 199,117 66,017 1,492,651 Nuclear fuel, at amortized cost — 14,495 — — — 14,495 Construction work in progress 7 41,312 1,311 51 6,275 48,956 Net Electric Plant $ 779,070 $ 211,575 $ 293,997 $ 199,168 $ 72,292 $ 1,556,102 |
Accounting For Asset Retireme_2
Accounting For Asset Retirement And Environmental Obligations (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Schedule Of Changes In Asset Retirement Obligations | The following represents changes in our asset retirement obligations for the years ended December 31, 2022 and 2021 (in thousands): Asset retirement obligations as of December 31, 2020 $ 179,133 Accretion expense 5,664 Asset retirement obligations as of December 31, 2021 $ 184,797 Accretion expense 5,873 Asset retirement obligations as of December 31, 2022 $ 190,670 |
Power Purchase Agreements (Tabl
Power Purchase Agreements (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulated Operations [Abstract] | |
Schedule Of Power Purchase Obligations | As of December 31, 2022, our power purchase obligations under the various agreements were as follows: Year Ended December 31, Capacity and Energy (in millions) 2023 $ 186.9 2024 29.0 2025 1.6 $ 217.5 |
Wholesale Power Contracts (Tabl
Wholesale Power Contracts (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Wholesale Power Contracts [Abstract] | |
Schedule of Revenues from Member Distribution Cooperatives | Revenues from our member distribution cooperatives for the past three years were as follows: Year Ended December 31, 2022 2021 2020 (in millions) Rappahannock Electric Cooperative $ 288.6 $ 223.3 $ 237.6 Shenandoah Valley Electric Cooperative 180.9 138.2 144.5 Delaware Electric Cooperative, Inc. 140.0 109.1 110.0 Choptank Electric Cooperative, Inc. 92.3 72.1 73.7 Southside Electric Cooperative 67.5 51.8 56.9 A&N Electric Cooperative 55.1 44.0 48.0 Mecklenburg Electric Cooperative 54.3 32.6 36.8 Prince George Electric Cooperative 25.8 20.2 22.9 Northern Neck Electric Cooperative 21.5 16.9 20.2 Community Electric Cooperative 13.9 10.5 11.0 BARC Electric Cooperative 11.2 8.2 9.2 Total $ 951.1 $ 726.9 $ 770.8 |
Fair Value Measurements (Tables
Fair Value Measurements (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Fair Value Disclosures [Abstract] | |
Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis | The following table summarizes our financial assets and liabilities measured at fair value on a recurring basis as of December 31, 2022 and 2021: Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable December 31, Assets Inputs Inputs 2022 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 73,945 $ 73,945 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 151,318 — — — Unrestricted investments and other (3) 279 — 279 — Derivatives - gas and power (4) 59,902 27,839 20,773 11,290 Total Financial Assets $ 285,444 $ 101,784 $ 21,052 $ 11,290 Derivatives - gas and power (4) $ 8,721 $ — $ 8,721 $ — Total Financial Liabilities $ 8,721 $ — $ 8,721 $ — Quoted Prices in Active Significant Markets for Other Significant Identical Observable Unobservable December 31, Assets Inputs Inputs 2021 (Level 1) (Level 2) (Level 3) (in thousands) Nuclear decommissioning trust (1) $ 89,227 $ 89,227 $ — $ — Nuclear decommissioning trust - net asset value (1)(2) 187,431 — — — Unrestricted investments and other (3) 212 — 212 — Derivatives - gas and power (4) 50,793 32,078 3,705 15,010 Total Financial Assets $ 327,663 $ 121,305 $ 3,917 $ 15,010 Derivatives - gas and power (4) $ 4,291 $ — $ 4,291 $ — Total Financial Liabilities $ 4,291 $ — $ 4,291 $ — (1) For additional information about our nuclear decommissioning trust, see Note 8—Investments. (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 the 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—Summary of Significant Accounting Policies. |
Derivatives And Hedging (Tables
Derivatives And Hedging (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule Of Outstanding Derivative Instruments | Outstanding derivative instruments, excluding contracts accounted for as normal purchase/normal sale, were as follows: Quantity As of As of Commodity Unit of Measure 2022 2021 Natural gas MMBTU 91,770,000 58,640,000 Purchased power - financial transmission rights MWh 8,450,239 9,156,789 |
Schedule Of Fair Value Of Derivative Instruments | The fair value of our derivative instruments, excluding contracts accounted for as normal purchase/normal sale, was as follows: Fair Value As of As of Balance Sheet Location 2022 2021 (in thousands) Derivatives in an asset position: Natural gas futures contracts Other assets $ 48,612 $ 35,783 Financial transmission rights Other assets 11,290 15,010 Total derivatives in an asset position $ 59,902 $ 50,793 Derivatives in a liability position: Natural gas futures contracts Other liabilities $ 8,721 $ 4,291 Total derivatives in a liability position $ 8,721 $ 4,291 |
Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital | The Effect of Derivative Instruments on the Consolidated Statements of Revenues, Expenses, and Patronage Capital for the Years Ended December 31, 2022 and 2021 Amount of Gain Amount of Gain Location of (Loss) Reclassified (Loss) Recognized Gain (Loss) from Regulatory in Regulatory Reclassified Asset/Liability Asset/Liability for from Regulatory into Income for Derivatives Accounted for Derivatives as of Asset/Liability the Year Utilizing Regulatory Accounting December 31, into Income Ended December 31, 2022 2021 2022 2021 (in thousands) (in thousands) Natural gas futures contracts $ 37,448 $ 34,703 Fuel $ 123,256 $ 26,758 Purchased power 11,290 15,010 Purchased Power 20,901 9,463 Total $ 48,738 $ 49,713 $ 144,157 $ 36,221 |
Investments (Tables)
Investments (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Investments [Abstract] | |
Schedule Of Investments | Investments were as follows as of December 31, 2022 and 2021: Gross Gross Unrealized Unrealized Fair Carrying Description Cost Gains Losses Value Value (in thousands) December 31, 2022 Nuclear decommissioning trust (1) Debt securities $ 86,770 $ — $ ( 13,083 ) $ 73,687 $ 73,687 Equity securities 93,878 64,139 ( 6,699 ) 151,318 151,318 Cash and other 258 — — 258 258 Total Nuclear Decommissioning Trust $ 180,906 $ 64,139 $ ( 19,782 ) $ 225,263 $ 225,263 Other Equity securities $ 238 $ 41 $ — $ 279 $ 279 Non-marketable equity investments 2,158 2,182 — 4,340 2,158 Total Other $ 2,396 $ 2,223 $ — $ 4,619 $ 2,437 $ 227,700 December 31, 2021 Nuclear decommissioning trust (1) Debt securities $ 84,701 $ 4,052 $ — $ 88,753 $ 88,753 Equity securities 92,916 94,923 ( 408 ) 187,431 187,431 Cash and other 474 — — 474 474 Total Nuclear Decommissioning Trust $ 178,091 $ 98,975 $ ( 408 ) $ 276,658 $ 276,658 Other Equity securities $ 157 $ 55 $ — $ 212 $ 212 Non-marketable equity investments 2,149 2,370 — 4,519 2,149 Total Other $ 2,306 $ 2,425 $ — $ 4,731 $ 2,361 $ 279,019 (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—Accounting for Asset Retirement and Environmental Obligations. Unrealized gains and losses on investments held in the nuclear decommissioning trust are deferred as a regulatory liability or regulatory asset, respectively. |
Schedule Of Contractual Maturities Of Debt Securities | Contractual maturities of debt securities as of December 31, 2022, were as follows: Less than More than Description 1 year 1-5 years 5-10 years 10 years Total (in thousands) Other (1) $ — $ — $ 73,687 $ — $ 73,687 Total $ — $ — $ 73,687 $ — $ 73,687 (1) The contractual maturities of other debt securities are measured using the effective duration of the bond fund within the nuclear decommissioning trust. |
Regulatory Assets And Liabili_2
Regulatory Assets And Liabilities (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule Of Regulatory Assets And Liabilities | Our regulatory assets and liabilities as of December 31, 2022 and 2021, were as follows: December 31, 2022 2021 (in thousands) Regulatory Assets: Unamortized losses on reacquired debt $ 787 $ 2,518 Deferred asset retirement costs 214 230 NOVEC contract termination fee 14,681 17,128 Interest rate hedge 1,461 1,604 Voluntary prepayment to NRECA Retirement Security Plan — 773 PJM capacity performance event, net 20,106 — Total Regulatory Assets $ 37,249 $ 22,253 Regulatory Assets included in Current Assets: Deferred energy $ 83,836 $ 5,005 Regulatory Liabilities: North Anna asset retirement obligation deferral $ 68,803 $ 72,226 North Anna nuclear decommissioning trust unrealized gain 44,357 98,567 Unamortized gains on reacquired debt 54 113 Deferred net unrealized gains on derivative instruments 48,739 49,713 Total Regulatory Liabilities $ 161,953 $ 220,619 |
Long-term Debt (Tables)
Long-term Debt (Tables) | 12 Months Ended |
Dec. 31, 2022 | |
Debt Disclosure [Abstract] | |
Schedule Of Long-term Debt | Long-term debt consists of the following: December 31, 2022 2021 (in thousands) $ 250,000,000 principal amount of First Mortgage Bonds, 2017 3.33 % $ 187,500 $ 200,000 $ 260,000,000 principal amount of First Mortgage Bonds, 2015 4.46 % 260,000 260,000 $ 72,000,000 principal amount of First Mortgage Bonds, 2015 4.56 % 72,000 72,000 $ 50,000,000 principal amount of First Mortgage Bonds, 2013 4.21 % 50,000 50,000 $ 50,000,000 principal amount of First Mortgage Bonds, 2013 4.36 % 50,000 50,000 $ 90,000,000 principal amount of First Mortgage Bonds, 2011 4.83 % 54,000 57,000 $ 165,000,000 principal amount of First Mortgage Bonds, 2011 5.54 % 148,500 156,750 $ 95,000,000 principal amount of First Mortgage Bonds, 2011 5.54 % 66,500 68,875 $ 250,000,000 principal amount of 2003 5.676 % 62,496 72,912 $ 300,000,000 principal amount of 2002 6.21 % 75,000 87,500 1,025,996 1,075,037 Debt issuance costs ( 4,788 ) ( 5,237 ) Current maturities ( 49,041 ) ( 49,041 ) $ 972,167 $ 1,020,759 |
Schedule Of Maturities Of Long-term Debt | Maturities of long-term debt for the next five years and thereafter are as follows: Year Ended December 31, (in thousands) 2023 $ 49,041 2024 49,041 2025 49,041 2026 49,041 2027 49,041 2028 and thereafter 780,791 $ 1,025,996 |
Summary Of Significant Accoun_4
Summary Of Significant Accounting Policies - Additional Information (Details) | 12 Months Ended | |||
Dec. 14, 2021 USD ($) | Dec. 31, 2022 USD ($) Cooperative Representative Member_class Product Member Segment | Dec. 31, 2021 USD ($) | Dec. 31, 2020 USD ($) | |
Significant Accounting Policies [Line Items] | ||||
Consolidated assets | $ 2,204,979,000 | $ 2,175,059,000 | ||
Number of classes of members | Member_class | 2 | |||
Number of Class A members | Member | 11 | |||
Number of representatives from each Class A member on the board of directors | Representative | 2 | |||
Number of representatives from each Class B member on the board of directors | Representative | 1 | |||
Reimbursement of nuclear fuel costs receivable | $ 1,900,000 | 2,400,000 | ||
Interest costs capitalized | $ 1,300,000 | 900,000 | $ 500,000 | |
Percentage of income received from members | 85% | |||
Number of Member Distributions Cooperatives | Cooperative | 11 | |||
Number of power products for sale | Product | 2 | |||
Percentage change in energy rate due to revision of energy adjustment rate | 2% | |||
Percentage of budgeted total interest charges | 20% | |||
Percentage of actual interest charges | 20% | |||
Member distribution cooperatives, amount prepaid | $ 105,800,000 | 92,300,000 | ||
Member distribution cooperatives, amount extended | 8,900,000 | 0 | ||
Deferred energy, asset | 83,800,000 | 5,000,000 | ||
Additional equity contribution | $ 8,700,000 | |||
Retirement of patronage capital | $ 8,700,000 | 8,740,000 | ||
Payment date of patronage capital | Mar. 25, 2022 | |||
Reduction of patronage capital | $ 8,700,000 | |||
Increase in accounts payable-members | $ 8,700,000 | |||
Accounts receivable–members | $ 111,838,000 | 63,037,000 | ||
Number of operating segments | Segment | 1 | |||
Number of reportable segments | Segment | 1 | |||
Long-term Debt [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Capitalized costs associated with the issuance of debt | $ 4,800,000 | 5,200,000 | ||
Deferred Charges And Other Assets - Other [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Capitalized costs associated with the issuance of debt | 300,000 | 600,000 | ||
Variable Interest Entity Primary Beneficiary [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Consolidated assets | $ 12,700,000 | $ 5,800,000 | ||
Maximum [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Derivative term | 3 years | |||
TEC [Member] | ||||
Significant Accounting Policies [Line Items] | ||||
Percentage of interest owned in subsidiary by our Class A members | 100% |
Summary Of Significant Accoun_5
Summary Of Significant Accounting Policies (Schedule Of Depreciation Rates) (Details) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Wildcat Point [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.10% | 3.10% | 3.10% |
North Anna [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.30% | 3.30% | 3.30% |
Clover [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 1.90% | 1.90% | 1.90% |
Louisa [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3.10% | 3.10% | 3.10% |
Marsh Run [Member] | |||
Property, Plant and Equipment [Line Items] | |||
Depreciation Rates | 3% | 3% | 3% |
Summary Of Significant Accoun_6
Summary Of Significant Accounting Policies - (Schedule of Operating Revenues) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounting Policies [Abstract] | |||
Energy revenues | $ 540,423 | $ 328,045 | $ 375,714 |
Renewable energy credits | 259 | 36 | 33 |
Demand revenues | 410,437 | 398,819 | 395,067 |
Total revenues from sales to member distribution cooperatives | 951,119 | 726,900 | 770,814 |
Energy revenues | 42,818 | 45,255 | 31,431 |
Renewable energy credits | 11,980 | 8,485 | 5,438 |
Demand revenues | 21 | ||
Total revenues from sales to non-members | 54,798 | 53,740 | 36,890 |
Total operating revenues | $ 1,005,917 | $ 780,640 | $ 807,704 |
Revenue, Product and Service [Extensible Enumeration] | us-gaap:ElectricityMember | us-gaap:ElectricityMember | us-gaap:ElectricityMember |
Summary Of Significant Accoun_7
Summary Of Significant Accounting Policies - (Schedule of Operating Revenues) (Parenthetical) (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Disaggregation of Revenue [Line Items] | |||
Non-members energy revenues | $ 42,818,000 | $ 45,255,000 | $ 31,431,000 |
TEC [Member] | |||
Disaggregation of Revenue [Line Items] | |||
Non-members energy revenues | $ 29,400,000 | $ 0 | $ 0 |
Summary Of Significant Accoun_8
Summary Of Significant Accounting Policies (Schedule Of Reduction In Revenues Utilizing Margin Stabilization) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Accounting Policies [Abstract] | |||
Margin Stabilization adjustment | $ 2,255 | $ 11,614 | $ 13,227 |
Summary Of Significant Accoun_9
Summary Of Significant Accounting Policies (Schedule Of Rate Changes Implemented To Address Under- And Over-Collection Of Energy Costs) (Details) | Jan. 01, 2023 | Jul. 01, 2022 | May 01, 2022 | Jan. 01, 2022 | Jan. 01, 2021 | Jan. 01, 2020 |
Significant Accounting Policies [Line Items] | ||||||
Percentage of total energy rate change | 47.70% | 6.70% | 20.30% | (15.90%) | (16.20%) | |
Subsequent Event [Member] | ||||||
Significant Accounting Policies [Line Items] | ||||||
Percentage of total energy rate change | (1.50%) |
Electric Plant (Schedule Of Net
Electric Plant (Schedule Of Net Electric Plan) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | $ 2,549,435 | $ 2,542,407 |
Accumulated depreciation | (1,116,531) | (1,049,756) |
Net Property, plant, and equipment | 1,432,904 | 1,492,651 |
Nuclear fuel, at amortized cost | 19,155 | 14,495 |
Construction work in progress | 56,075 | 48,956 |
Net Electric Plant | 1,508,134 | 1,556,102 |
Wildcat Point [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 879,319 | 877,789 |
Accumulated depreciation | (125,832) | (98,726) |
Net Property, plant, and equipment | 753,487 | 779,063 |
Construction work in progress | 245 | 7 |
Net Electric Plant | 753,732 | 779,070 |
North Anna [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 418,073 | 416,259 |
Accumulated depreciation | (272,036) | (260,491) |
Net Property, plant, and equipment | 146,037 | 155,768 |
Nuclear fuel, at amortized cost | 19,155 | 14,495 |
Construction work in progress | 47,378 | 41,312 |
Net Electric Plant | 212,570 | 211,575 |
Clover [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 708,240 | 707,333 |
Accumulated depreciation | (427,304) | (414,647) |
Net Property, plant, and equipment | 280,936 | 292,686 |
Construction work in progress | 159 | 1,311 |
Net Electric Plant | 281,095 | 293,997 |
Combustion Turbine Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 441,000 | 440,168 |
Accumulated depreciation | (254,425) | (241,051) |
Net Property, plant, and equipment | 186,575 | 199,117 |
Construction work in progress | 227 | 51 |
Net Electric Plant | 186,802 | 199,168 |
Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Property, plant, and equipment | 102,803 | 100,858 |
Accumulated depreciation | (36,934) | (34,841) |
Net Property, plant, and equipment | 65,869 | 66,017 |
Construction work in progress | 8,066 | 6,275 |
Net Electric Plant | $ 73,935 | $ 72,292 |
Electric Plant - Additional Inf
Electric Plant - Additional Information (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 USD ($) Unit Facility mi MW | Dec. 31, 2021 USD ($) | |
Wildcat Point [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Power facility output | 980 | |
North Anna [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Power facility output | 1,892 | |
Undivided ownership interest | 11.60% | |
Number of units | Unit | 2 | |
Percentage of costs responsible for | 11.60% | |
Outstanding accounts payable balance | $ | $ 5.6 | $ 7.9 |
Clover [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Power facility output | 877 | |
Undivided ownership interest | 50% | |
Number of units | Unit | 2 | |
Outstanding accounts payable balance | $ | $ 6 | $ 5.5 |
Combustion Turbine Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Number of combustion turbine facilities | Facility | 2 | |
Distributed Generation Facilities [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Number of distributed facilities | Facility | 6 | |
Other [Member] | ||
Property, Plant and Equipment [Line Items] | ||
Transmission lines | mi | 110 |
Accounting For Asset Retireme_3
Accounting For Asset Retirement And Environmental Obligations - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2019 | Dec. 31, 2021 | |
Asset Retirement And Environmental Obligations [Line Items] | |||
Increase (decrease) in asset retirement obligations | $ 37.6 | ||
North Anna [Member] | |||
Asset Retirement And Environmental Obligations [Line Items] | |||
North Anna's nuclear decommissioning asset retirement obligation | $ 166.3 | $ 161.5 | |
Decommission study period | 4 years | ||
Asset retirement obligations cash flow estimates useful life | 20 years | ||
Asset retirement obligations cash flow estimates related to application for additional operating license extension | 20 years |
Accounting For Asset Retireme_4
Accounting For Asset Retirement And Environmental Obligations (Schedule Of Changes In Asset Retirement Obligations) (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | |||
Beginning balance | $ 184,797 | $ 179,133 | |
Accretion expense | 5,873 | 5,664 | $ 5,463 |
Ending balance | $ 190,670 | $ 184,797 | $ 179,133 |
Power Purchase Agreements - Add
Power Purchase Agreements - Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Public Utilities General Disclosures [Line Items] | |||
Energy requirements from owned generating facilities | 51.50% | 55.60% | 52% |
Purchased power | $ 462,526 | $ 234,471 | $ 250,546 |
ACES [Member] | |||
Public Utilities General Disclosures [Line Items] | |||
Change in power price collateral | 5,600 | ||
PJM Transactions [Member] | |||
Public Utilities General Disclosures [Line Items] | |||
Change in power price collateral | $ 7,900 | $ 5,200 |
Power Purchase Agreements (Sche
Power Purchase Agreements (Schedule Of Power Purchase Obligations) (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2022 USD ($) | |
Regulated Operations [Abstract] | |
2023 | $ 186.9 |
2024 | 29 |
2025 | 1.6 |
Power Purchase Obligations | $ 217.5 |
Wholesale Power Contracts - Add
Wholesale Power Contracts - Additional Information (Details) | 1 Months Ended | 12 Months Ended |
May 31, 2023 MW | Dec. 31, 2022 Member MW | |
Wholesale Power Contracts [Line Items] | ||
Required period for termination of wholesale power contract | 3 years | |
Purchases under limited contract exceptions, percent of power received from owned generation or other suppliers | 5% | |
Description of limited exceptions | There are two additional limited exceptions to the all-requirements nature of our wholesale power contracts. One exception permits each of our member distribution cooperatives, with 180 days prior written notice, to receive up to the greater of | |
Prior written notice period | 180 days | |
Purchases under limited contract exceptions, amount of power allowable under contractual exception received from owned generation or other suppliers | 5 | |
Removal of load requirements under exception | 144 | |
Current reduction in demand and associated energy related to limited exception if fully utilized | 181 | |
Forecast [Member] | ||
Wholesale Power Contracts [Line Items] | ||
Return of load requirements under exception | 16 | |
Maximum [Member] | ||
Wholesale Power Contracts [Line Items] | ||
Exception for purchases of hydroelectric power allocated from SEPA | 2% | |
Mainland Virginia [Member] | ||
Wholesale Power Contracts [Line Items] | ||
Principal exceptions to the all-requirements obligations by members | Member | 8 |
Wholesale Power Contracts (Sche
Wholesale Power Contracts (Schedule Of Revenues From Member Distribution Cooperatives) (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Related Party Transaction [Line Items] | |||
Member distribution revenue | $ 951.1 | $ 726.9 | $ 770.8 |
Rappahannock Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 288.6 | 223.3 | 237.6 |
Shenandoah Valley Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 180.9 | 138.2 | 144.5 |
Delaware Electric Cooperative, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 140 | 109.1 | 110 |
Choptank Electric Cooperative, Inc. [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 92.3 | 72.1 | 73.7 |
Southside Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 67.5 | 51.8 | 56.9 |
A&N Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 55.1 | 44 | 48 |
Mecklenburg Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 54.3 | 32.6 | 36.8 |
Prince George Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 25.8 | 20.2 | 22.9 |
Northern Neck Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 21.5 | 16.9 | 20.2 |
Community Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | 13.9 | 10.5 | 11 |
BARC Electric Cooperative [Member] | |||
Related Party Transaction [Line Items] | |||
Member distribution revenue | $ 11.2 | $ 8.2 | $ 9.2 |
Fair Value Measurements (Financ
Fair Value Measurements (Financial Assets And Liabilities Measured At Fair Value On A Recurring Basis) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 | |
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | $ 285,444 | $ 327,663 | |
Total Financial Liabilities | 8,721 | 4,291 | |
Nuclear Decommissioning Trust [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [1] | 73,945 | 89,227 |
Nuclear Decommissioning Trust - Net Asset Value [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [1],[2] | 151,318 | 187,431 |
Unrestricted Investment And Other [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [3] | 279 | 212 |
Derivatives - Gas And Power [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [4] | 59,902 | 50,793 |
Total Financial Liabilities | [4] | 8,721 | 4,291 |
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | 101,784 | 121,305 | |
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Nuclear Decommissioning Trust [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [1] | 73,945 | 89,227 |
Quoted Prices In Active Markets For Identical Assets (Level 1) [Member] | Derivatives - Gas And Power [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [4] | 27,839 | 32,078 |
Significant Other Observable Inputs (Level 2) [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | 21,052 | 3,917 | |
Total Financial Liabilities | 8,721 | 4,291 | |
Significant Other Observable Inputs (Level 2) [Member] | Unrestricted Investment And Other [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [3] | 279 | 212 |
Significant Other Observable Inputs (Level 2) [Member] | Derivatives - Gas And Power [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [4] | 20,773 | 3,705 |
Total Financial Liabilities | [4] | 8,721 | 4,291 |
Significant Unobservable Inputs (Level 3) | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | 11,290 | 15,010 | |
Significant Unobservable Inputs (Level 3) | Derivatives - Gas And Power [Member] | |||
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items] | |||
Total Financial Assets | [4] | $ 11,290 | $ 15,010 |
[1] For additional information about our nuclear decommissioning trust, see Note 8—Investments. 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 the Consolidated Balance Sheet. Unrestricted investments and other includes investments that are related to equity securities. 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—Summary of Significant Accounting Policies. |
Derivatives And Hedging (Schedu
Derivatives And Hedging (Schedule Of Outstanding Derivative Instruments) (Details) | 12 Months Ended | |
Dec. 31, 2022 MMBTU MWh | Dec. 31, 2021 MMBTU MWh | |
Natural Gas [Member] | ||
Derivative [Line Items] | ||
Quantity | MMBTU | 91,770,000 | 58,640,000 |
Financial Transmission Rights [Member] | ||
Derivative [Line Items] | ||
Quantity | MWh | 8,450,239 | 9,156,789 |
Derivatives And Hedging (Sche_2
Derivatives And Hedging (Schedule Of Fair Value Of Derivative Instruments) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Derivatives, Fair Value [Line Items] | ||
Total derivatives in an asset position | $ 59,902 | $ 50,793 |
Total derivatives in a liability position | 8,721 | 4,291 |
Natural Gas Future Contracts [Member] | Other Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivatives in an asset position | 48,612 | 35,783 |
Natural Gas Future Contracts [Member] | Other Liabilities [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivatives in a liability position | 8,721 | 4,291 |
Financial Transmission Rights [Member] | Other Assets [Member] | ||
Derivatives, Fair Value [Line Items] | ||
Total derivatives in an asset position | $ 11,290 | $ 15,010 |
Derivatives And Hedging (Sche_3
Derivatives And Hedging (Schedule Of Derivative Instruments On The Statement Of Revenues, Expenses, And Patronage Capital) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | $ 48,738 | $ 49,713 |
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | 144,157 | 36,221 |
Natural Gas Future Contracts [Member] | Fuel [Member] | Operating Expense Fuel [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | 37,448 | 34,703 |
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | 123,256 | 26,758 |
Financial Transmission Rights [Member] | Purchased Power [Member] | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||
Amount of Gain (Loss) Recognized in Regulatory Asset/Liability for Derivatives | 11,290 | 15,010 |
Amount Of Gain (Loss) Reclassified from Regulatory Asset/Liability into Income | $ 20,901 | $ 9,463 |
Investments (Schedule Of Invest
Investments (Schedule Of Investments) (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule of Invested Securities [Line Items] | ||
Equity, Cost | $ 2,158 | $ 2,149 |
Equity Method Investment Gross Unrealized Gains | 2,182 | 2,370 |
Equity, Fair Value | 4,340 | 4,519 |
Other, Cost | 2,396 | 2,306 |
Other Gross Unrealized Gains | 2,223 | 2,425 |
Other, Fair Value | 4,619 | 4,731 |
Total Other | 2,437 | 2,361 |
Total Investments | 227,700 | 279,019 |
Total Nuclear Decommissioning Trust | 225,263 | 276,658 |
Nuclear Decommissioning Trust [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Investments, Debt securities, Cost | 86,770 | 84,701 |
Investments, Debt securities, Gross Unrealized Gains | 4,052 | |
Investments, Debt securities, Gross Unrealized Losses | (13,083) | |
Investments, Debt securities | 73,687 | 88,753 |
Investments, Equity securities, Cost | 93,878 | 92,916 |
Investments, Equity securities, Gross Unrealized Gains | 64,139 | 94,923 |
Investments, Equity securities, Gross Unrealized Losses | (6,699) | (408) |
Investments, Equity securities | 151,318 | 187,431 |
Investments, Cash and other | 258 | 474 |
Investments, Cost | 180,906 | 178,091 |
Investments, Gross Unrealized Gains | 64,139 | 98,975 |
Investments, Gross Unrealized Loss | (19,782) | (408) |
Total Nuclear Decommissioning Trust | 225,263 | 276,658 |
Other [Member] | ||
Schedule of Invested Securities [Line Items] | ||
Investments, Equity securities, Cost | 238 | 157 |
Investments, Equity securities, Gross Unrealized Gains | 41 | 55 |
Total Investments | $ 279 | $ 212 |
Investments (Schedule Of Contra
Investments (Schedule Of Contractual Maturities Of Debt Securities) (Details) $ in Thousands | Dec. 31, 2022 USD ($) |
Investments [Abstract] | |
Other debt securities, 5-10 years | $ 73,687 |
Other debt securities, Total | 73,687 |
Contractual maturities of securities, 5-10 years | 73,687 |
Contractual maturities of securities, Total | $ 73,687 |
Regulatory Assets And Liabili_3
Regulatory Assets And Liabilities (Schedule Of Regulatory Assets And Liabilities) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 37,249 | $ 22,253 |
Regulatory liabilities | 161,953 | 220,619 |
Deferred Energy [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory Assets included in Current Assets | 83,836 | 5,005 |
North Anna Nuclear Decommissioning Trust Unrealized Gain [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 44,357 | 98,567 |
North Anna Asset Retirement Obligation Deferral [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 68,803 | 72,226 |
Unamortized Gains On Reacquired Debt [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 54 | 113 |
Interest Rate Hedge [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 1,461 | 1,604 |
Deferred Net Unrealized Gains On Derivative Instruments [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory liabilities | 48,739 | 49,713 |
Unamortized Losses On Reacquired Debt [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 787 | 2,518 |
Deferred Asset Retirement Costs [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 214 | 230 |
NOVEC Contract Termination Fee [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | 14,681 | 17,128 |
Voluntary Prepayment To NRECA Retirement Security Plan [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 773 | |
PJM Capacity Performance Event [Member] | ||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||
Regulatory assets | $ 20,106 |
Regulatory Assets And Liabili_4
Regulatory Assets And Liabilities - Additional Information (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Apr. 30, 2013 | Dec. 31, 2013 | Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||||
Multi Employer pension payment | $ 7,700 | $ 7,700 | ||
Regulatory assets | $ 37,249 | $ 22,253 | ||
PJM Capacity Performance Event [Member] | ||||
Schedule Of Regulatory Assets And Liabilities [Line Items] | ||||
Regulatory assets | $ 20,106 |
Long-term Debt (Schedule Of Lon
Long-term Debt (Schedule Of Long-term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Instrument [Line Items] | ||
Long-term debt | $ 1,025,996 | $ 1,075,037 |
Debt issuance costs | (4,788) | (5,237) |
Current maturities | (49,041) | (49,041) |
Long-term debt, excluding current maturities | 972,167 | 1,020,759 |
$250,000,000 principal amount of First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 187,500 | 200,000 |
$260,000,000 principal amount of First Mortgage Bonds, 2015 Series A due 2044 at an interest rate of 4.46% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 260,000 | 260,000 |
$72,000,000 principal amount of First Mortgage Bonds, 2015 Series B due 2053 at an interest rate of 4.56% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 72,000 | 72,000 |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 50,000 | 50,000 |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 50,000 | 50,000 |
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 54,000 | 57,000 |
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due 2040 at an interest rate of 5.54% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 148,500 | 156,750 |
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due 2050 at an interest rate of 5.54% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 66,500 | 68,875 |
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676% | ||
Debt Instrument [Line Items] | ||
Long-term debt | 62,496 | 72,912 |
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21% | ||
Debt Instrument [Line Items] | ||
Long-term debt | $ 75,000 | $ 87,500 |
Long-term Debt (Schedule Of L_2
Long-term Debt (Schedule Of Long-term Debt) (Parenthetical) (Details) - USD ($) | Dec. 31, 2022 | Dec. 31, 2021 |
$250,000,000 principal amount of First Mortgage Bonds, 2017 Series A due 2037 at an interest rate of 3.33% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 250,000,000 | $ 250,000,000 |
Debt instrument, interest rate | 3.33% | 3.33% |
$260,000,000 principal amount of First Mortgage Bonds, 2015 Series A due 2044 at an interest rate of 4.46% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 260,000,000 | $ 260,000,000 |
Debt instrument, interest rate | 4.46% | 4.46% |
$72,000,000 principal amount of First Mortgage Bonds, 2015 Series B due 2053 at an interest rate of 4.56% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 72,000,000 | $ 72,000,000 |
Debt instrument, interest rate | 4.56% | 4.56% |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series A due 2043 at an interest rate of 4.21% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 50,000,000 | $ 50,000,000 |
Debt instrument, interest rate | 4.21% | 4.21% |
$50,000,000 principal amount of First Mortgage Bonds, 2013 Series B due 2053 at an interest rate of 4.36% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 50,000,000 | $ 50,000,000 |
Debt instrument, interest rate | 4.36% | 4.36% |
$90,000,000 principal amount of First Mortgage Bonds, 2011 Series A due 2040 at an interest rate of 4.83% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 90,000,000 | $ 90,000,000 |
Debt instrument, interest rate | 4.83% | 4.83% |
$165,000,000 principal amount of First Mortgage Bonds, 2011 Series B due 2040 at an interest rate of 5.54% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 165,000,000 | $ 165,000,000 |
Debt instrument, interest rate | 5.54% | 5.54% |
$95,000,000 principal amount of First Mortgage Bonds, 2011 Series C due 2050 at an interest rate of 5.54% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 95,000,000 | $ 95,000,000 |
Debt instrument, interest rate | 5.54% | 5.54% |
$250,000,000 principal amount of 2003 Series A Bonds due 2028 at an interest rate of 5.676% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 250,000,000 | $ 250,000,000 |
Debt instrument, interest rate | 5.676% | 5.676% |
$300,000,000 principal amount of 2002 Series B Bonds due 2028 at an interest rate of 6.21% | ||
Debt Instrument [Line Items] | ||
Debt instrument, face amount | $ 300,000,000 | $ 300,000,000 |
Debt instrument, interest rate | 6.21% | 6.21% |
Long-term Debt - Additional Inf
Long-term Debt - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Debt Disclosure [Abstract] | ||
Net loss on reacquired debt | $ 0.7 | $ 2.4 |
Fair value of long-term debt | $ 942.8 | $ 1,292.5 |
Percent of patronage capital to total long-term debt and patronage capital required for distribution | 20% | |
Maximum distribution as percent of patronage capital | 5% |
Long-term Debt (Schedule Of Mat
Long-term Debt (Schedule Of Maturities Of Long-term Debt) (Details) - USD ($) $ in Thousands | Dec. 31, 2022 | Dec. 31, 2021 |
Debt Disclosure [Abstract] | ||
2023 | $ 49,041 | |
2024 | 49,041 | |
2025 | 49,041 | |
2026 | 49,041 | |
2027 | 49,041 | |
2028 and thereafter | 780,791 | |
Long-term debt | $ 1,025,996 | $ 1,075,037 |
Liquidity Resources - Additiona
Liquidity Resources - Additional Information (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
Debt Instrument [Line Items] | ||
Line of credit outstanding | $ 50,000,000 | |
Revolving Credit Facility [Member] | ||
Debt Instrument [Line Items] | ||
Credit facility, interest rate | 5.35% | 1.10% |
Line of credit outstanding | $ 50,000,000 | $ 0 |
Revolving Credit Facility [Member] | Minimum [Member] | ||
Debt Instrument [Line Items] | ||
Margins-for-interest ratio | 110% | |
Revolving Credit Facility [Member] | Maximum [Member] | ||
Debt Instrument [Line Items] | ||
Debt to capitalization ratio | 85% | |
Revolving Credit Facility [Member] | LIBOR [Member] | Minimum [Member] | ||
Debt Instrument [Line Items] | ||
Spread on variable rate | 0.90% | |
Revolving Credit Facility [Member] | LIBOR [Member] | Maximum [Member] | ||
Debt Instrument [Line Items] | ||
Spread on variable rate | 1.50% | |
Revolving Credit Facility [Member] | Federal Funds Effective Rate [Member] | ||
Debt Instrument [Line Items] | ||
Spread on variable rate | 0.50% | |
Revolving Credit Facility [Member] | Daily LIBOR [Member] | ||
Debt Instrument [Line Items] | ||
Spread on variable rate | 1% | |
Revolving Credit Facility [Member] | Daily LIBOR [Member] | Minimum [Member] | ||
Debt Instrument [Line Items] | ||
Spread on variable rate margin | 0% | |
Revolving Credit Facility [Member] | Daily LIBOR [Member] | Maximum [Member] | ||
Debt Instrument [Line Items] | ||
Spread on variable rate margin | 0.50% | |
Revolving Credit Facility [Member] | Through March 3, 2022 [Member] | ||
Debt Instrument [Line Items] | ||
Credit facility, maximum borrowing capacity | $ 500,000,000 | |
Revolving Credit Facility [Member] | March 4, 2022 through February 28, 2025 [Member] | ||
Debt Instrument [Line Items] | ||
Credit facility, maximum borrowing capacity | 400,000,000 | |
Letter of Credit [Member] | ||
Debt Instrument [Line Items] | ||
Line of credit outstanding | $ 500,000 | $ 500,000 |
Employee Benefit Plans - Additi
Employee Benefit Plans - Additional Information (Details) - USD ($) $ in Millions | 1 Months Ended | 12 Months Ended | |||
Apr. 30, 2013 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | Dec. 31, 2013 | |
Postemployment Benefits [Line Items] | |||||
Funded percentage (greater than) | 80% | 80% | |||
Multi Employer pension payment | $ 7.7 | $ 7.7 | |||
Contributions | $ 4 | $ 4 | $ 4 | ||
Companies contribution as percentage of total contributions made (less than) | 5% | 5% | 5% | ||
Pension expense, inclusive of administrative fees | $ 5.4 | $ 5.5 | $ 5.1 | ||
Amortization of voluntary prepayment | $ 0.8 | 0.8 | 0.8 | ||
Matching contributions percentage | 2% | ||||
Matching contributions | $ 0.3 | $ 0.3 | $ 0.3 | ||
Executive Benefit Restoration Plan [Member] | Other Liabilities [Member] | |||||
Postemployment Benefits [Line Items] | |||||
Supplemental benefit for employees related to IRC limitations | $ 1.2 |
Supplemental Cash Flows Infor_2
Supplemental Cash Flows Information - Additional Information (Details) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 | |
Supplemental Cash Flow Elements [Abstract] | |||
Cash paid for interest, net of amounts capitalized | $ 53 | $ 53.3 | $ 57.9 |
Capital expenditures incurred but not yet paid | $ 2.7 | $ 2.7 | $ 3.8 |
Commitments And Contingencies -
Commitments And Contingencies - Additional Information (Details) - USD ($) | 3 Months Ended | 12 Months Ended | |
Sep. 30, 2022 | Dec. 31, 2022 | Dec. 31, 2021 | |
Commitments and Contingencies Disclosure [Abstract] | |||
Liability protection, per nuclear incident, per site | $ 13,700,000,000 | ||
Liability protection period for nuclear incidents subject to change for inflation | 5 years | ||
Liability protection per nuclear incidents decreased | $ 13,700,000,000 | $ 13,500,000,000 | |
Nuclear liability assessment per reactor | $ 138,000,000 | ||
Nuclear liability assessment per licensed reactor per year | 20,000,000 | ||
Contingent liability for coverage, maximum | $ 34,800,000 |