Oglethorpe Power 10-Q 12 Nov 21 2021 Q3 Quarterly report Financial data

Cover Page

Cover Page	9 Months Ended
	Sep. 30, 2021shares
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2021
Document Transition Report	false
Entity File Number	333-192954
Entity Registrant Name	OGLETHORPE POWER CORP
Entity Incorporation, State or Country Code	GA
Entity Tax Identification Number	58-1211925
Entity Address, Address Line One	2100 East Exchange Place
Entity Address, City or Town	Tucker
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30084-5336
City Area Code	770
Local Phone Number	270-7600
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	0
Entity Central Index Key	0000788816
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	Q3

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020
Electric plant:
In service	$ 9,790,913	$ 9,394,112
Right-of-use assets—finance leases	302,732	302,732
Less: Accumulated provision for depreciation	(5,397,418)	(4,968,294)
Net in service	4,696,227	4,728,550
Nuclear fuel, at amortized cost	365,685	358,728
Construction work in progress	6,534,429	5,783,579
Total electric plant	11,596,341	10,870,857
Investments and funds:
Nuclear decommissioning trust fund	635,958	598,181
Investment in associated companies	73,099	74,844
Long-term investments	678,704	518,065
Restricted investments	73,400	306,601
Other	30,441	29,189
Total investments and funds	1,491,602	1,526,880
Current assets:
Cash and cash equivalents	452,943	405,511
Restricted short-term investments	246,580	180,986
Receivables	205,128	152,466
Inventories, at average cost	237,018	280,289
Prepayments and other current assets	94,370	33,839
Total current assets	1,236,039	1,053,091
Deferred charges:
Regulatory assets	898,117	731,438
Prepayments to Georgia Power	34,859	37,601
Other	59,208	20,289
Total deferred charges	992,184	789,328
Total assets	15,316,166	14,240,156
Capitalization:
Patronage capital and membership fees	1,120,652	1,072,642
Long-term debt	10,330,910	10,298,385
Obligation under finance leases	65,207	68,876
Other	27,402	26,861
Total capitalization	11,544,171	11,466,764
Current liabilities:
Long-term debt and finance leases due within one year	263,010	208,649
Short-term borrowings	1,023,374	383,498
Accounts payable	159,712	162,249
Accrued interest	78,276	72,434
Member power bill prepayments, current	26,207	46,068
Other current liabilities	82,285	68,932
Total current liabilities	1,632,864	941,830
Deferred credits and other liabilities:
Asset retirement obligations	1,214,467	1,135,983
Member power bill prepayments, non-current	86,492	98,113
Regulatory liabilities	816,229	566,399
Other	21,943	31,067
Total deferred credits and other liabilities	2,139,131	1,831,562
Total equity and liabilities	$ 15,316,166	$ 14,240,156

Consolidated Statements of Reve

Consolidated Statements of Revenues and Expenses (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020
Operating revenues:
Total operating revenues	$ 460,822	$ 366,239	$ 1,195,280	$ 1,038,857
Operating expenses:
Fuel	214,681	131,925	436,277	282,677
Production	99,321	94,071	298,171	303,705
Depreciation and amortization	69,758	61,758	204,654	186,370
Purchased power	16,920	16,419	50,706	49,366
Accretion	14,117	14,204	41,839	40,830
Total operating expenses	414,797	318,377	1,031,647	862,948
Operating margin	46,025	47,862	163,633	175,909
Other income:
Investment income	12,299	11,672	36,389	36,210
Other	2,516	1,832	4,964	5,733
Total other income	14,815	13,504	41,353	41,943
Interest charges:
Interest expense	105,201	101,600	312,927	305,128
Allowance for debt funds used during construction	(56,179)	(51,518)	(164,628)	(153,595)
Amortization of debt discount and expense	2,911	2,813	8,677	8,482
Net interest charges	51,933	52,895	156,976	160,015
Net margin	8,907	8,471	48,010	57,837
Members
Operating revenues:
Total operating revenues	437,240	365,937	1,171,433	1,038,218
Non-Members
Operating revenues:
Total operating revenues	$ 23,582	$ 302	$ 23,847	$ 639

Consolidated Statements of Patr

Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) - USD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Sep. 30, 2021	Sep. 30, 2020
Increase (Decrease) in Members' Capital
Net margin	$ 8,907			$ 8,471			$ 48,010	$ 57,837
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Beginning balance	1,111,745	$ 1,098,600	$ 1,072,642	1,066,113	$ 1,039,951	$ 1,016,747	1,072,642	1,016,747
Net margin	8,907	13,145	25,958	8,471	26,162	23,204
Ending balance	$ 1,120,652	$ 1,111,745	$ 1,098,600	$ 1,074,584	$ 1,066,113	$ 1,039,951	$ 1,120,652	$ 1,074,584

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020
Cash flows from operating activities:
Net margin	$ 48,010	$ 57,837
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	297,976	278,872
Accretion cost	41,839	40,830
Amortization of deferred gains	(1,341)	(1,341)
Allowance for equity funds used during construction	(267)	(306)
Deferred outage costs	(27,163)	(36,502)
Gain on sale of investments	(11,665)	(14,122)
Regulatory deferral of costs associated with nuclear decommissioning	(15,592)	(11,482)
Other	(639)	(2,566)
Change in operating assets and liabilities:
Receivables	(51,283)	(22,751)
Inventories	46,686	3,836
Prepayments and other current assets	(6,199)	(30,914)
Accounts payable	(4,487)	(28,764)
Accrued interest	5,842	10,483
Accrued taxes	6,788	35,004
Other current liabilities	522	(16,433)
Member power bill prepayments	(31,482)	(56,975)
Rate management program collections	117,600	114,006
Total adjustments	367,135	260,875
Net cash provided by operating activities	415,145	318,712
Cash flows from investing activities:
Property additions	(891,162)	(983,902)
Plant acquisition	233,156	0
Activity in nuclear decommissioning trust fund—Purchases	(556,879)	(393,369)
Activity in nuclear decommissioning trust fund - Proceeds	550,956	387,277
Decrease (increase) in restricted investments	167,607	(7,282)
Activity in other long-term investments—Purchases	(340,877)	(285,842)
Activity in other long-term investments - Proceeds	184,083	136,476
Other	8,139	9,075
Net cash used in investing activities	(1,111,289)	(1,137,567)
Cash flows from financing activities:
Long-term debt proceeds	517,524	2,045,685
Long-term debt payments	(440,548)	(1,274,196)
Increase (decrease) in short-term borrowings, net	639,876	(16,255)
Other	30,124	(1,123)
Net cash provided by financing activities	746,976	754,111
Net increase (decrease) in cash, cash equivalents and restricted cash	50,832	(64,744)
Cash, cash equivalents and restricted cash at beginning of period	405,511	448,612
Cash, cash equivalents and restricted at end of period	456,343	383,868
Cash paid for—
Interest (net of amounts capitalized)	141,206	139,878
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	42,964	22,086
Accrued property additions at end of period	$ 71,443	$ 94,365

General

General	9 Months Ended
	Sep. 30, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	General. The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, our financial condition and results of operations for the three-month and nine-month periods ended September 30, 2021 and 2020. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) revenue recognition, such as determining the nature and timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading.

Fair Value

Fair Value	9 Months Ended
	Sep. 30, 2021
Fair Value Disclosures [Abstract]
Fair Value	Fair Value. Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: • Level 1. Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded. • Level 2. Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs. • Level 3. Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques: 1. Market approach. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs. 2. Income approach. The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. 3. Cost approach. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 2021 and December 31, 2020. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs September 30, 2021 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 225,255 $ 225,255 $ — $ — International equity trust 142,018 — 142,018 — Corporate bonds and debt 78,874 — 78,306 568 US Treasury securities 54,212 54,212 — — Mortgage backed securities 33,712 — 33,712 — Domestic mutual funds 74,861 74,861 — — Municipal bonds 1,130 — 1,130 — Federal agency securities 9,792 — 9,792 — Non-US Gov't bonds & private placements 2,696 — 2,696 — Other 13,408 13,408 — — Long-term investments: International equity trust 35,015 — 35,015 — Corporate bonds and debt 15,590 — 15,272 318 US Treasury securities 13,440 13,440 — — Mortgage backed securities 11,582 — 11,582 — Domestic mutual funds 271,354 271,354 — — Federal agency securities 290 — 290 — Treasury STRIPS 325,398 — 325,398 — Other 6,035 6,035 — — Natural gas swaps 93,930 — 93,930 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2020 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 198,325 $ 198,325 $ — $ — International equity trust 120,645 — 120,645 — Corporate bonds and debt 98,129 — 97,788 341 US Treasury securities 46,963 46,963 — — Mortgage backed securities 45,039 — 45,039 — Domestic mutual funds 70,813 70,813 — — Municipal bonds 1,362 — 1,362 — Federal agency securities 6,054 — 6,054 — Other 10,851 7,720 3,131 — Long-term investments: International equity trust 31,378 — 31,378 — Corporate bonds and debt 29,870 — 29,661 209 US Treasury securities 7,437 7,437 — — Mortgage backed securities 11,432 — 11,432 — Domestic mutual funds 224,536 224,536 — — Federal agency securities 537 — 537 — Treasury STRIPS 209,165 — 209,165 — Other 3,710 3,710 — — Natural gas swaps 10,248 — 10,248 — The Level 2 investments above in corporate bonds and debt, federal agency securities, and mortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs at or near the valuation date. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period. The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchange traded. Although these securities may be liquid and priced daily, their inputs are not observable. The estimated fair values of our long-term debt, including current maturities at September 30, 2021 and December 31, 2020 were as follows: 2021 2020 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 10,700,098 $ 12,568,831 $ 10,619,826 $ 13,161,146 The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of September 30, 2021 and December 31, 2020 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. For cash and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statement of cash flows. We are exposed to credit risk as a result of entering into these derivative arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions. It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of September 30, 2021, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. We have entered into International Swaps and Derivatives Association agreements with our natural gas contract counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. At September 30, 2021 and December 31, 2020, the estimated fair values of our natural gas contracts were net assets of approximately $93,930,000 and net liabilities of approximately $10,248,000, respectively. At September 30, 2021, one of our counterparties was required to post credit collateral totaling $3,400,000 under our natural gas swap agreements. At December 31, 2020, none of our counterparties were required to post credit collateral. Such collateral is classified as restricted cash and included in the Prepayments and other current assets line item within our unaudited consolidated balance sheets. The following table reflects the notional volume of our natural gas derivatives at September 30, 2021 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2021 4.4 2022 24.2 2023 23.8 2024 23.2 2025 19.9 2026 12.9 Total 108.4 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 2021 and December 31, 2020. Balance Sheet Location Fair Value 2021 2020 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 47,303 $ 222 Natural gas swaps Other deferred charges $ 46,627 $ — Liabilities: Natural gas swaps Other current liabilities $ — $ 2,305 Natural gas swaps Other deferred credits $ — $ 8,165 The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and nine months ended September 30, 2021 and 2020. Statement of Three Months Ended Nine Months Ended 2021 2020 2021 2020 (dollars in thousands) Natural gas swaps gains Fuel $ 15,831 $ 339 $ 18,229 $ 339 Natural gas swaps losses Fuel — (8,721) (1,311) (20,314) Total $ 15,831 $ (8,382) $ 16,918 $ (19,975) The following table presents the unrealized gains and losses on derivative instruments deferred on the balance sheet at September 30, 2021 and December 31, 2020. Balance Sheet Location 2021 2020 (dollars in thousands) Natural gas swaps Regulatory asset $ — $ 10,248 Regulatory liability 93,930 — Total $ 93,930 $ 10,248

Investments Securities

Investments Securities	9 Months Ended
	Sep. 30, 2021
Investments, Debt and Equity Securities [Abstract]
Investment Securities	Investment Securities. Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. The following tables summarize debt and equity securities at September 30, 2021 and December 31, 2020. Gross Unrealized (dollars in thousands) September 30, 2021 Cost Gains Losses Fair Equity $ 300,141 $ 253,423 $ (4,727) $ 548,837 Debt 743,582 6,727 (3,928) 746,381 Other 19,444 — — 19,444 Total $ 1,063,167 $ 260,150 $ (8,655) $ 1,314,662 Gross Unrealized (dollars in thousands) December 31, 2020 Cost Gains Losses Fair Equity $ 262,564 $ 219,658 $ (8,127) $ 474,095 Debt 613,271 18,090 (641) 630,720 Other 11,431 — — 11,431 Total $ 887,266 $ 237,748 $ (8,768) $ 1,116,246

Recently Issued or Adopted Acco

Recently Issued or Adopted Accounting Pronouncements	9 Months Ended
	Sep. 30, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently Issued or Adopted Accounting Pronouncements	Recently Issued or Adopted Accounting Pronouncements. In March 2020, the Financial Accounting Standards Board (FASB) issued “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting”. The amendments in this update apply to all entities that have contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this update provide optional expedients and exceptions for applying U.S. GAAP to transactions affected by reference rate reform if certain criteria are met. The expedients and exceptions provided by the amendments in this update do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity has elected certain optional expedients that are retained through the end of the hedging relationship. In January 2021, the FASB issued “Reference Rate Reform (Topic 848): Scope,” to further clarify the scope of the reference rate reform guidance in Topic 848. The amendments in this update refine the scope of Topic 848 to clarify that certain optional expedients and exceptions therein for contract modifications and hedge accounting apply to contracts that are affected by the discounting transition. Specifically, modifications related to reference rate reform would not be considered an event that requires reassessment of previous accounting conclusions. The amendments in this update also amend the expedients and exceptions in Topic 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments in these updates are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the future impact of this standard on our consolidated financial statements. In December 2019, the FASB issued “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”, as part of its initiative to reduce complexity in the accounting standards. The amendments in the standard remove certain exceptions and also clarify and simplify various aspects of accounting for income taxes. The new standard was effective for us prospectively for annual reporting periods beginning after December 15, 2020, and interim periods therein. Early adoption was permitted, which we elected not to do. The adoption of this standard on January 1, 2021 did not have a material impact on our consolidated financial statements.

Revenue Recognition

Revenue Recognition	9 Months Ended
	Sep. 30, 2021
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition. As an electric membership cooperative, our principal business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated to pay us for capacity and energy we furnish under the wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. For information regarding regulatory accounting, see Note J. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are generally recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract. We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note K. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. For the nine-month periods ended September 30, 2021 and 2020, we provided approximately 61% and 57% of our members' energy requirements, respectively. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2021, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. At September 30, 2021 and September 30, 2020, we recognized refund liabilities totaling $16,500,000 and $21,400,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members for the three and nine months ended September 30, 2021 and 2020 were as follows: Three Months Ended Nine Months Ended (dollars in thousands) 2021 2020 2021 2020 Capacity revenues $ 228,048 $ 222,187 $ 716,303 $ 721,836 Energy revenues 209,192 143,750 455,130 316,382 Total $ 437,240 $ 365,937 $ 1,171,433 $ 1,038,218 Member energy requirements supplied 65 % 60 % 61 % 57 % Receivables from contracts with our members at September 30, 2021 and December 31, 2020 were $156,095,000 and $135,462,000, respectively. Sales to non-members during the three and nine months ended September 30, 2021 and 2020 were as follows: Three Months Ended Nine Months Ended (dollars in thousands) 2021 2020 2021 2020 Energy revenues $ 23,582 $ 302 $ 23,847 $ 639 Receivables from non-member energy sales at September 30, 2021 and December 31, 2020 were $6,562,000 and $0, respectively. Energy revenues to non-members for the three and nine months ended September 30, 2021 were primarily from the sale of the Effingham Energy Facility's (Effingham) output into the wholesale market. See Note O for additional information regarding the Effingham acquisition. There were no capacity revenues to non-members for the three and nine months ended September 30, 2021 and 2020. Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members during the nine months ended September 30, 2021 and 2020 were $11,601,000 and $11,805,000, respectively. The cumulative amount billed since inception of the program totaled $107,544,000. In 2018, we began a rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the nine months ended September 30, 2021 and 2020 were $115,837,000 and $93,390,000, respectively. Funds collected through this program are invested and held until applied to members' bills. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members' bills. The cumulative amount billed since inception of the program totaled $330,165,000.

Leases

Leases	9 Months Ended
	Sep. 30, 2021
Leases [Abstract]
Leases	Leases. As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the three and nine months ended September 30, 2021 and 2020 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset or liability. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through March 16, 2024. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification September 30, 2021 December 31, 2020 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (266,288) (262,774) Total finance lease assets $ 36,444 $ 39,958 Lease liabilities—Finance leases Obligations under finance leases $ 65,207 $ 68,876 Long-term debt and finance leases due within one year 7,146 6,773 Total finance lease liabilities $ 72,353 $ 75,649 Classification September 30, 2021 December 31, 2020 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service $ 2,540 $ 3,283 Total operating lease assets $ 2,540 $ 3,283 Lease liabilities—Operating leases Capitalization—Other $ 1,677 $ 2,388 Other current liabilities 876 990 Total operating lease liabilities $ 2,553 $ 3,378 Three months ended Nine months ended Lease Cost Classification September 30, 2021 September 30, 2020 September 30, 2021 September 30, 2020 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,693 $ 1,344 $ 4,726 $ 4,032 Interest on lease liabilities Interest expense 2,045 2,217 6,133 6,651 Operating lease cost: Inventory (1) & production expense 270 286 809 1,081 Total leased cost $ 4,008 $ 3,847 $ 11,668 $ 11,764 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. September 30, 2021 December 31, 2020 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 7.13 7.86 Operating leases 8.01 7.27 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.76 % 4.63 % Nine months ended September 30, 2021 September 30, 2020 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,180 $ 4,516 Operating cash flows from operating leases $ 890 $ 1,301 Financing cash flows from finance leases $ 3,295 $ 2,959 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities at September 30, 2021 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2021 $ 7,474 $ 230 $ 7,704 2022 14,949 929 15,878 2023 14,949 708 15,657 2024 14,949 234 15,183 2025 14,949 72 15,021 Thereafter 40,582 1,011 41,593 Total lease payments $ 107,852 $ 3,184 $ 111,036 Less: imputed interest (35,499) (631) (36,130) Present value of lease liabilities $ 72,353 $ 2,553 $ 74,906 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and nine months ended September 30, 2021 and 2020 was as follows: Three Months Ended September 30, Nine months ended September 30, 2021 2020 2021 2020 (dollars in thousands) Lease income $ 1,603 $ 1,543 $ 4,806 $ 4,633
Leases	Leases. As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the three and nine months ended September 30, 2021 and 2020 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset or liability. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through March 16, 2024. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification September 30, 2021 December 31, 2020 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (266,288) (262,774) Total finance lease assets $ 36,444 $ 39,958 Lease liabilities—Finance leases Obligations under finance leases $ 65,207 $ 68,876 Long-term debt and finance leases due within one year 7,146 6,773 Total finance lease liabilities $ 72,353 $ 75,649 Classification September 30, 2021 December 31, 2020 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service $ 2,540 $ 3,283 Total operating lease assets $ 2,540 $ 3,283 Lease liabilities—Operating leases Capitalization—Other $ 1,677 $ 2,388 Other current liabilities 876 990 Total operating lease liabilities $ 2,553 $ 3,378 Three months ended Nine months ended Lease Cost Classification September 30, 2021 September 30, 2020 September 30, 2021 September 30, 2020 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,693 $ 1,344 $ 4,726 $ 4,032 Interest on lease liabilities Interest expense 2,045 2,217 6,133 6,651 Operating lease cost: Inventory (1) & production expense 270 286 809 1,081 Total leased cost $ 4,008 $ 3,847 $ 11,668 $ 11,764 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. September 30, 2021 December 31, 2020 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 7.13 7.86 Operating leases 8.01 7.27 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.76 % 4.63 % Nine months ended September 30, 2021 September 30, 2020 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,180 $ 4,516 Operating cash flows from operating leases $ 890 $ 1,301 Financing cash flows from finance leases $ 3,295 $ 2,959 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities at September 30, 2021 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2021 $ 7,474 $ 230 $ 7,704 2022 14,949 929 15,878 2023 14,949 708 15,657 2024 14,949 234 15,183 2025 14,949 72 15,021 Thereafter 40,582 1,011 41,593 Total lease payments $ 107,852 $ 3,184 $ 111,036 Less: imputed interest (35,499) (631) (36,130) Present value of lease liabilities $ 72,353 $ 2,553 $ 74,906 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and nine months ended September 30, 2021 and 2020 was as follows: Three Months Ended September 30, Nine months ended September 30, 2021 2020 2021 2020 (dollars in thousands) Lease income $ 1,603 $ 1,543 $ 4,806 $ 4,633

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	9 Months Ended
	Sep. 30, 2021
Contingencies and Regulatory Matters
Contingencies and Regulatory Matters	Contingencies and Regulatory Matters. We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined. Environmental Matters. As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any potential new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs. Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent. On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer, of which we are a co-owner, have impacted

Restricted Cash and Investments

Restricted Cash and Investments	9 Months Ended
	Sep. 30, 2021
Restricted Investments Note [Abstract]
Restricted Cash and Investments	Restricted Cash and Investments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. As of October 1, 2020, deposits earned interest at 4% per annum. Beginning October 1, 2021, the rate was set at the 1-year floating treasury rate, which was 0.09% per annum, and will reset annually on October 1 of each year thereafter. The program no longer allows additional funds to be deposited into the account. At September 30, 2021 and December 31, 2020, we had restricted investments totaling $319,980,000 and $487,587,000, respectively, of which $73,400,000 and $306,601,000, respectively, were classified as long-term. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the unaudited consolidated balance sheets that sum to the total of the same such amounts reported in the unaudited consolidated statements of cash flows. Classification Nine months ended September 30, 2021 September 30, 2020 (dollars in thousands) Cash and cash equivalents $ 452,943 $ 383,868 Restricted cash included in Prepayments and other current assets 3,400 — Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 456,343 $ 383,868

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities. We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members. The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members. The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets at September 30, 2021 and December 31, 2020. 2021 2020 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 34,307 $ 35,433 Amortization of financing leases(b) 34,555 35,328 Outage costs(c) 36,734 35,232 Asset retirement obligations—Ashpond and other(k) 272,923 242,832 Depreciation expense - other(d) 37,329 38,396 Depreciation expense - Plant Wansley(e) 149,641 — Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,702 55,430 Interest rate options cost(g) 130,367 126,813 Deferral of effects on net margin—Smith Energy Facility(h) 144,161 148,620 Other regulatory assets(o) 2,398 13,354 Total Regulatory Assets $ 898,117 $ 731,438 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 21,124 $ 20,054 Deferral of effects on net margin—Hawk Road Energy Facility(h) 17,407 17,869 Major maintenance reserve(j) 61,127 39,776 Amortization of financing leases(b) 9,182 11,356 Deferred debt service adder(k) 134,833 123,772 Asset retirement obligations—Nuclear(l) 142,368 130,901 Revenue deferral plan(m) 334,645 220,111 Natural gas hedges(n) 93,930 — Other regulatory liabilities(o) 1,613 2,560 Total Regulatory Liabilities $ 816,229 $ 566,399 Net Regulatory Assets $ 81,888 $ 165,039 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 22 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Represents the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which is expected as early as fall of 2022. Amortization will commence upon retirement of Plant Wansley and end no later than December 31, 2040. (f) Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence when Vogtle Unit No. 3 is placed in service. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (m) Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period. (n) Represents deferral associated with unrealized gains on our natural gas hedges. (o) The amortization periods for other regulatory assets range up to 29 years and the amortization periods of other regulatory liabilities range up to 6 years.

Member Power Bill Prepayments

Member Power Bill Prepayments	9 Months Ended
	Sep. 30, 2021
Member Power Bill Prepayments
Member Power Bill Prepayments	Member Power Bill Prepayments. We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through December 2026, with the majority of the balance scheduled to be credited by the end of 2023.

Debt

Debt	9 Months Ended
	Sep. 30, 2021
Debt Disclosure [Abstract]
Debt	Debt. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a multi-advance term loan facility (the Facility) under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility are used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII loan guarantee program (Eligible Project Costs). Borrowings under the Original FFB Notes could not exceed $3,057,069,461, of which $335,471,604 was designated for capitalized interest. We have advanced all amounts available under the Original FFB Notes. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original FFB Notes due to timing of borrowing and lower than expected interest rates. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in late 2017. At September 30, 2021, borrowings under the Additional FFB Note totaled $867,000,000. At September 30, 2021, aggregate Department of Energy-guaranteed borrowings, including capitalized interest, totaled $3,880,348,382. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began on February 20, 2020. As of September 30, 2021, we have repaid $158,313,000 of principal on the FFB Notes. Interest rates on advances during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. Advances under the Additional FFB Note may be requested on a quarterly basis through November 30, 2023. Future advances under the Facility are subject to satisfaction of customary conditions, as well as (i) certification of compliance with the requirements of the Title XVII loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, (iv) no Project Adverse Event (as described in Note M) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note M) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of Energy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, (vi) evidence of compliance with the applicable wage requirements of the Davis-Bacon Act, as amended, (vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement. We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option the Federal Financing Bank's commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve twelve b) Rural Utilities Service Guaranteed Loans: For the nine-month period ended September 30, 2021, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $270,524,000 for long-term financing of general and environmental improvements at existing plants. In October 2021, we received an additional $12,508,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Pollution Control Revenue Bonds: In August 2021, we redeemed $245,605,000 of Series 2009 and 2010 pollution control revenue bonds. d) Lines of Credit: On October 1, 2021, we amended our bilateral credit facility with JPMorgan Chase to extend the expiration date to October 2024 and reduce the commitment amount from $363,000,000 to $350,000,000.

Vogtle Units No. 3 and No. 4 Co

Vogtle Units No. 3 and No. 4 Construction Project	9 Months Ended
	Sep. 30, 2021
Vogtle Units No. 3 and No. 4 Construction Project
Vogtle Units No. 3 and No. 4 Construction Project	Vogtle Units No. 3 and No. 4 Construction Project. We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. At September 30, 2021, our total investment for our 30% interest in the additional Vogtle units was approximately $6.8 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. Since March 2020, the number of active cases of COVID-19 at the site has fluctuated and impacted productivity levels and pace of activity completion. As a result, the project has faced challenges, including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. In 2021, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit No. 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional testing and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers and Georgia Power has disclosed that it projects an in-service date for Unit No. 3 in the third quarter of 2022. Our current budget reflects our expectation of an in-service date for Unit No. 3 in September 2022. As a result of productivity challenges, at the end of the second quarter 2021 Southern Nuclear also further extended milestone dates for Unit No. 4. Those productivity challenges continued into the third quarter and, in addition, some craft and support resources were diverted temporarily to support construction efforts on Unit No. 3. The in-service date for Unit No. 4 primarily depends on overall construction productivity as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 in second quarter 2023. Our current budget anticipates an in-service date for Unit No. 4 in June 2023. During the fourth quarter of 2020, Georgia Power established $375 million of additional contingency (of which our 30% share was $112.5 million). At March 31, 2021, Georgia Power assigned approximately $183 million (of which our 30% interest was $55 million) of that construction contingency to the base capital cost forecast for costs primarily associated with the schedule extension for Unit No. 3 to December 2021, construction productivity, support resources and construction remediation work. During the first quarter of 2021, Georgia Power also established an additional $106 million of construction contingency (of which our 30% share was $32 million). At June 30, 2021, the remaining previously established project-level contingency of approximately $300 million (of which our 30% interest was $90 million) and an additional $746 million (of which our 30% interest was $224 million) was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units No. 3 and No. 4, construction remediation work for Unit No. 3, and construction productivity and support resources for Units No. 3 and No. 4. At June 30, 2021, Georgia Power also established an additional $260 million of construction contingency (of which our 30% interest was $78 million) to replenish the project-level construction contingency. Considering the factors above, during the third quarter 2021, the construction contingency established in the second quarter and an additional $278 million (of which our 30% share was $83 million) was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units No. 3 and No. 4, construction productivity and support resources for Units No. 3 and No. 4, and construction remediation work for Unit No. 3. At September 30, 2021, Georgia Power added $300 million (of which our 30% interest is $90 million) to replenish construction contingency. Georgia Power has stated its expectation to allocate the remainder of this project-level contingency by completion of the project. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated by Georgia Power to be between $350 million and $438 million (of which our 30% interest is $105 million to $131 million) and is included in the project budget. Our budget for our 30% ownership interest in Vogtle Units No. 3 and No. 4, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency, is $8.25 billion and is based on commercial operation dates of September 2022 and June 2023 for Units No. 3 and No. 4, respectively. The project-level contingency is separate and in addition to our Oglethorpe-level contingency. The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, provides additional margin to cover potential cost, schedule, and financing risks associated with our share of the project which may not be covered by project-level contingencies. As construction progresses, the Oglethorpe-level contingency may continue to fluctuate as it represents the difference between known project-level costs and contingencies and our total budget of $8.25 billion. At the end of the project, if there is remaining Oglethorpe-level contingency, we will adjust our project budget to remove this contingency and bill our members based on the actual project costs. The table below shows our project budget and actual costs through September 30, 2021 for our 30% interest in the project. (in millions) Project Budget Actual Costs at September 30, 2021 Remaining Project Budget Construction Costs (1) $ 6,140 $ 5,342 $ 798 Financing Costs 1,778 1,443 335 Total Costs $ 7,918 $ 6,785 $ 1,133 Project-Level Contingency $ 90 $ — $ 90 Oglethorpe-Level Contingency 242 — 242 Total Contingency $ 332 $ — $ 332 Totals $ 8,250 $ 6,785 $ 1,465 (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement. The Oglethorpe-level contingency in our current budget is expected to be sufficient to cover a few months of additional delays beyond our assumed in-service dates of September 2022 and June 2023 for Unit No. 3 and Unit No. 4, respectively, such as a three-month delay on Unit No. 4 from June 2023 to September 2023. Any further delays are expected to impact our cost by approximately $55 million per month for both units and approximately $25 million per month for Unit No. 4 only, including financing costs. As construction, including subcontract work, continues and testing and system turnover activities increase, risks remain that ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at this scale), including the spent fuel pools, any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. In connection with the additional construction remediation work described above, Southern Nuclear reviewed the project’s construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the Nuclear Regulatory Commission began a special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. On August 26, 2021, the Nuclear Regulatory Commission made preliminary findings of two apparent violations of Nuclear Regulatory Commission regulations, one of low to moderate safety significance, and the other of greater than very low safety significance. The Nuclear Regulatory Commission also made a finding of very low safety significance related to a non-cited violation of its regulations. The Nuclear Regulatory Commission stated that the apparent nonconformances associated with these findings do not represent an immediate safety concern because Unit No. 3 construction is still underway and issues implicating inspections, tests, analyses, and acceptance criteria must be resolved prior to loading nuclear fuel into the Unit No. 3 reactor. Findings from this or other inspections could require additional remediation and/or further Nuclear Regulatory Commission oversight and may impact the projected in-service dates. In addition, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the inspections, tests, analyses, and acceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, have arisen or may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria, are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners. In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. These joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further on September 26, 2018 by the Term Sheet that was memorialized on February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) to the Joint Ownership Agreements (as amended, the Joint Ownership Agreements). As a result of an increase in the total project capital cost forecast and Georgia Power’s decision not to seek recovery of its allocation of the increase in the base capital costs and the increased construction budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring (VCM) report in 2018, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners unanimously voted to continue construction of Vogtle Units No. 3 and No. 4. In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC that mitigated certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that: • each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's nineteenth VCM report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs; • Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a Force Majeure Event, that exceed the EAC in the nineteenth VCM report by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and • Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions such as costs that are a result of a Force Majeure Event, that exceed the EAC in the nineteenth VCM report by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest). If the EAC is revised and exceeds the EAC in the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option to be exercised between 120 and 180 days following the date the revised construction budget is voted on by the Co-owners to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. In this event, Georgia Power would have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Co-owner. If Georgia Power accepts the offer to purchase a portion of another Co-owner’s ownership interest in Vogtle Units No. 3 and No. 4, the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Co-owner and by Georgia Power as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Co-owner in accordance with the second and third bullets above will be treated as payments made by the applicable Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a portion of our 30% ownership interest. Georgia Power and the other Co-owners do not agree on (i) the starting dollar amount for each Co-owner’s option to tender a portion of its ownership interest to Georgia Power under the freeze provision of the Global Amendments or (ii) the starting dollar amount and extent to which costs that are the result of a Force Majeure Event (such as COVID-19) impact the calculation of the cost-sharing provisions of the Global Amendments. The nineteenth VCM report total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. At September 30, 2021, budget increases since the nineteenth VCM have reached $2.4 billion for all Co-owners. As a result of these increases, we believe that the tender option will be triggered at the next Co-owner construction budget vote scheduled for February 2022 and that Georgia Power’s obligation to contribute dollars to the Co-owners under the cost-sharing provisions will commence as early as the first half of 2022. Georgia Power and the other Co-owners recently clarified the process for the freeze provision to provide for a decision between 120 and 180 days after the tender option is triggered which will provide additional time to resolve these matters.

Measurement of Credit Losses on

Measurement of Credit Losses on Financial Instruments	9 Months Ended
	Sep. 30, 2021
Accounting Policies [Abstract]
Measurement of Credit Losses on Financial Instruments	Measurement of Credit Losses on Financial Instruments. The financial assets we hold that are subject to the new credit losses standard are predominately accounts receivable and certain cash equivalents classified as held-to-maturity debt (e.g. commercial paper). Our receivables are generally due within thirty days or less with a significant portion related to billings to our members. See Note F for information regarding our member receivables. Commercial paper issuances we invest in are rated as investment grade and backed by a credit facility. Given our historical experience, the short duration lifetime of these financial assets and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of these financial assets is remote and we have not recognized an allowance for credit losses.

Plant Acquisition

Plant Acquisition	9 Months Ended
	Sep. 30, 2021
Business Combinations [Abstract]
Plant acquisition	Plant Acquisition. On July 8, 2021, we acquired Effingham County Power, LLC, which owned the Effingham Energy Facility located near Savannah, Georgia, from Effingham County Power Holdings, LLC, an affiliate of the Carlyle Group, Inc. Effingham consists of a natural gas-fired combined cycle unit with an aggregate summer planning reserve generation capacity of approximately 511 megawatts. Subsequently, we dissolved Effingham County Power, LLC and transferred all of its assets and liabilities to Oglethorpe. The purchase price was $233,156,000 and the acquisition also included other transaction costs of approximately $1,382,000 (consisting primarily of legal and professional services). We accounted for the acquisition as an asset acquisition. We financed the acquisition on an interim basis through the issuance of commercial paper. We submitted a loan application and have received a conditional loan commitment from the Rural Utilities Service for long-term financing of this acquisition. For any amounts not funded through the Rural Utilities Service, we intend to issue first mortgage bonds. We expect that any financing from the Rural Utilities Service or through first mortgage bonds will be secured under our first mortgage indenture. The following amounts represent the identifiable assets acquired and liabilities assumed in the Effingham acquisition: Classification (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: Electric plant in service, net $ 229,215 Inventories, at average cost 3,264 Other current assets 3,167 Other current liabilities (2,490) Total identifiable net assets $ 233,156

Recently Issued or Adopted Ac_2

Recently Issued or Adopted Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2021
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently Issued or Adopted Accounting Pronouncements	Recently Issued or Adopted Accounting Pronouncements. In March 2020, the Financial Accounting Standards Board (FASB) issued “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting”. The amendments in this update apply to all entities that have contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this update provide optional expedients and exceptions for applying U.S. GAAP to transactions affected by reference rate reform if certain criteria are met. The expedients and exceptions provided by the amendments in this update do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity has elected certain optional expedients that are retained through the end of the hedging relationship. In January 2021, the FASB issued “Reference Rate Reform (Topic 848): Scope,” to further clarify the scope of the reference rate reform guidance in Topic 848. The amendments in this update refine the scope of Topic 848 to clarify that certain optional expedients and exceptions therein for contract modifications and hedge accounting apply to contracts that are affected by the discounting transition. Specifically, modifications related to reference rate reform would not be considered an event that requires reassessment of previous accounting conclusions. The amendments in this update also amend the expedients and exceptions in Topic 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments in these updates are effective for all entities as of March 12, 2020 through December 31, 2022. We are currently evaluating the future impact of this standard on our consolidated financial statements. In December 2019, the FASB issued “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”, as part of its initiative to reduce complexity in the accounting standards. The amendments in the standard remove certain exceptions and also clarify and simplify various aspects of accounting for income taxes. The new standard was effective for us prospectively for annual reporting periods beginning after December 15, 2020, and interim periods therein. Early adoption was permitted, which we elected not to do. The adoption of this standard on January 1, 2021 did not have a material impact on our consolidated financial statements.

Fair Value (Tables)

Fair Value (Tables)	9 Months Ended
	Sep. 30, 2021
Fair Value Disclosures [Abstract]
Schedule of assets and liabilities measured at fair value on a recurring basis	The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 2021 and December 31, 2020. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs September 30, 2021 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 225,255 $ 225,255 $ — $ — International equity trust 142,018 — 142,018 — Corporate bonds and debt 78,874 — 78,306 568 US Treasury securities 54,212 54,212 — — Mortgage backed securities 33,712 — 33,712 — Domestic mutual funds 74,861 74,861 — — Municipal bonds 1,130 — 1,130 — Federal agency securities 9,792 — 9,792 — Non-US Gov't bonds & private placements 2,696 — 2,696 — Other 13,408 13,408 — — Long-term investments: International equity trust 35,015 — 35,015 — Corporate bonds and debt 15,590 — 15,272 318 US Treasury securities 13,440 13,440 — — Mortgage backed securities 11,582 — 11,582 — Domestic mutual funds 271,354 271,354 — — Federal agency securities 290 — 290 — Treasury STRIPS 325,398 — 325,398 — Other 6,035 6,035 — — Natural gas swaps 93,930 — 93,930 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2020 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 198,325 $ 198,325 $ — $ — International equity trust 120,645 — 120,645 — Corporate bonds and debt 98,129 — 97,788 341 US Treasury securities 46,963 46,963 — — Mortgage backed securities 45,039 — 45,039 — Domestic mutual funds 70,813 70,813 — — Municipal bonds 1,362 — 1,362 — Federal agency securities 6,054 — 6,054 — Other 10,851 7,720 3,131 — Long-term investments: International equity trust 31,378 — 31,378 — Corporate bonds and debt 29,870 — 29,661 209 US Treasury securities 7,437 7,437 — — Mortgage backed securities 11,432 — 11,432 — Domestic mutual funds 224,536 224,536 — — Federal agency securities 537 — 537 — Treasury STRIPS 209,165 — 209,165 — Other 3,710 3,710 — — Natural gas swaps 10,248 — 10,248 —
Schedule of estimated fair values of long-term debt, including current maturities	The estimated fair values of our long-term debt, including current maturities at September 30, 2021 and December 31, 2020 were as follows: 2021 2020 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 10,700,098 $ 12,568,831 $ 10,619,826 $ 13,161,146

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year	The following table reflects the notional volume of our natural gas derivatives at September 30, 2021 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2021 4.4 2022 24.2 2023 23.8 2024 23.2 2025 19.9 2026 12.9 Total 108.4
Schedule of fair value of derivative instruments and effect on consolidated balance sheets	The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 2021 and December 31, 2020. Balance Sheet Location Fair Value 2021 2020 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 47,303 $ 222 Natural gas swaps Other deferred charges $ 46,627 $ — Liabilities: Natural gas swaps Other current liabilities $ — $ 2,305 Natural gas swaps Other deferred credits $ — $ 8,165
Schedule of the realized gains and (losses) on derivative instruments recognized in margin	The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and nine months ended September 30, 2021 and 2020. Statement of Three Months Ended Nine Months Ended 2021 2020 2021 2020 (dollars in thousands) Natural gas swaps gains Fuel $ 15,831 $ 339 $ 18,229 $ 339 Natural gas swaps losses Fuel — (8,721) (1,311) (20,314) Total $ 15,831 $ (8,382) $ 16,918 $ (19,975)
Schedule of unrealized losses on derivative instruments deferred on the balance sheet	The following table presents the unrealized gains and losses on derivative instruments deferred on the balance sheet at September 30, 2021 and December 31, 2020. Balance Sheet Location 2021 2020 (dollars in thousands) Natural gas swaps Regulatory asset $ — $ 10,248 Regulatory liability 93,930 — Total $ 93,930 $ 10,248

Investment Securities (Tables)

Investment Securities (Tables)	9 Months Ended
	Sep. 30, 2021
Investments, Debt and Equity Securities [Abstract]
Summary of debt and equity securities	The following tables summarize debt and equity securities at September 30, 2021 and December 31, 2020. Gross Unrealized (dollars in thousands) September 30, 2021 Cost Gains Losses Fair Equity $ 300,141 $ 253,423 $ (4,727) $ 548,837 Debt 743,582 6,727 (3,928) 746,381 Other 19,444 — — 19,444 Total $ 1,063,167 $ 260,150 $ (8,655) $ 1,314,662 Gross Unrealized (dollars in thousands) December 31, 2020 Cost Gains Losses Fair Equity $ 262,564 $ 219,658 $ (8,127) $ 474,095 Debt 613,271 18,090 (641) 630,720 Other 11,431 — — 11,431 Total $ 887,266 $ 237,748 $ (8,768) $ 1,116,246

Revenue Recognition (Tables)

Revenue Recognition (Tables)	9 Months Ended
	Sep. 30, 2021
Members
Revenue Recognition
Schedule of sales to members	Sales to members for the three and nine months ended September 30, 2021 and 2020 were as follows: Three Months Ended Nine Months Ended (dollars in thousands) 2021 2020 2021 2020 Capacity revenues $ 228,048 $ 222,187 $ 716,303 $ 721,836 Energy revenues 209,192 143,750 455,130 316,382 Total $ 437,240 $ 365,937 $ 1,171,433 $ 1,038,218 Member energy requirements supplied 65 % 60 % 61 % 57 %
Schedule of sales to non-members	Sales to members for the three and nine months ended September 30, 2021 and 2020 were as follows: Three Months Ended Nine Months Ended (dollars in thousands) 2021 2020 2021 2020 Capacity revenues $ 228,048 $ 222,187 $ 716,303 $ 721,836 Energy revenues 209,192 143,750 455,130 316,382 Total $ 437,240 $ 365,937 $ 1,171,433 $ 1,038,218 Member energy requirements supplied 65 % 60 % 61 % 57 %
Non-Members
Revenue Recognition
Schedule of sales to members	Sales to non-members during the three and nine months ended September 30, 2021 and 2020 were as follows: Three Months Ended Nine Months Ended (dollars in thousands) 2021 2020 2021 2020 Energy revenues $ 23,582 $ 302 $ 23,847 $ 639
Schedule of sales to non-members	Sales to non-members during the three and nine months ended September 30, 2021 and 2020 were as follows: Three Months Ended Nine Months Ended (dollars in thousands) 2021 2020 2021 2020 Energy revenues $ 23,582 $ 302 $ 23,847 $ 639

Leases (Tables)

Leases (Tables)	9 Months Ended
	Sep. 30, 2021
Leases [Abstract]
Schedule of balance sheet impact of leases	For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification September 30, 2021 December 31, 2020 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (266,288) (262,774) Total finance lease assets $ 36,444 $ 39,958 Lease liabilities—Finance leases Obligations under finance leases $ 65,207 $ 68,876 Long-term debt and finance leases due within one year 7,146 6,773 Total finance lease liabilities $ 72,353 $ 75,649 Classification September 30, 2021 December 31, 2020 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service $ 2,540 $ 3,283 Total operating lease assets $ 2,540 $ 3,283 Lease liabilities—Operating leases Capitalization—Other $ 1,677 $ 2,388 Other current liabilities 876 990 Total operating lease liabilities $ 2,553 $ 3,378
Schedule of lease cost	Three months ended Nine months ended Lease Cost Classification September 30, 2021 September 30, 2020 September 30, 2021 September 30, 2020 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,693 $ 1,344 $ 4,726 $ 4,032 Interest on lease liabilities Interest expense 2,045 2,217 6,133 6,651 Operating lease cost: Inventory (1) & production expense 270 286 809 1,081 Total leased cost $ 4,008 $ 3,847 $ 11,668 $ 11,764 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed.
Summary of lease terms and discount rates	September 30, 2021 December 31, 2020 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 7.13 7.86 Operating leases 8.01 7.27 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.76 % 4.63 %
Schedule of cash paid for amounts included in the measurement of lease liabilities	Nine months ended September 30, 2021 September 30, 2020 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,180 $ 4,516 Operating cash flows from operating leases $ 890 $ 1,301 Financing cash flows from finance leases $ 3,295 $ 2,959 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ —
Schedule of maturities of finance and operating lease liabilities	Maturity analysis of our finance and operating lease liabilities at September 30, 2021 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2021 $ 7,474 $ 230 $ 7,704 2022 14,949 929 15,878 2023 14,949 708 15,657 2024 14,949 234 15,183 2025 14,949 72 15,021 Thereafter 40,582 1,011 41,593 Total lease payments $ 107,852 $ 3,184 $ 111,036 Less: imputed interest (35,499) (631) (36,130) Present value of lease liabilities $ 72,353 $ 2,553 $ 74,906
Schedule of lessor's income from leases	Lease income recognized during the three and nine months ended September 30, 2021 and 2020 was as follows: Three Months Ended September 30, Nine months ended September 30, 2021 2020 2021 2020 (dollars in thousands) Lease income $ 1,603 $ 1,543 $ 4,806 $ 4,633

Restricted Cash and Investmen_2

Restricted Cash and Investments (Tables)	9 Months Ended
	Sep. 30, 2021
Restricted Investments Note [Abstract]
Reconciliation of cash, cash equivalents and restricted cash	The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the unaudited consolidated balance sheets that sum to the total of the same such amounts reported in the unaudited consolidated statements of cash flows. Classification Nine months ended September 30, 2021 September 30, 2020 (dollars in thousands) Cash and cash equivalents $ 452,943 $ 383,868 Restricted cash included in Prepayments and other current assets 3,400 — Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 456,343 $ 383,868

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2021
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets and liabilities	The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets at September 30, 2021 and December 31, 2020. 2021 2020 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 34,307 $ 35,433 Amortization of financing leases(b) 34,555 35,328 Outage costs(c) 36,734 35,232 Asset retirement obligations—Ashpond and other(k) 272,923 242,832 Depreciation expense - other(d) 37,329 38,396 Depreciation expense - Plant Wansley(e) 149,641 — Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,702 55,430 Interest rate options cost(g) 130,367 126,813 Deferral of effects on net margin—Smith Energy Facility(h) 144,161 148,620 Other regulatory assets(o) 2,398 13,354 Total Regulatory Assets $ 898,117 $ 731,438 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 21,124 $ 20,054 Deferral of effects on net margin—Hawk Road Energy Facility(h) 17,407 17,869 Major maintenance reserve(j) 61,127 39,776 Amortization of financing leases(b) 9,182 11,356 Deferred debt service adder(k) 134,833 123,772 Asset retirement obligations—Nuclear(l) 142,368 130,901 Revenue deferral plan(m) 334,645 220,111 Natural gas hedges(n) 93,930 — Other regulatory liabilities(o) 1,613 2,560 Total Regulatory Liabilities $ 816,229 $ 566,399 Net Regulatory Assets $ 81,888 $ 165,039 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 22 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Represents the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which is expected as early as fall of 2022. Amortization will commence upon retirement of Plant Wansley and end no later than December 31, 2040. (f) Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization will commence when Vogtle Unit No. 3 is placed in service. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (m) Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period. (n) Represents deferral associated with unrealized gains on our natural gas hedges. (o) The amortization periods for other regulatory assets range up to 29 years and the amortization periods of other regulatory liabilities range up to 6 years.

Vogtle Units No. 3 and No. 4 _2

Vogtle Units No. 3 and No. 4 Construction Project (Tables)	9 Months Ended
	Sep. 30, 2021
Vogtle Units No. 3 and No. 4 Construction Project
Schedule of Project Budget and Actual Costs	The table below shows our project budget and actual costs through September 30, 2021 for our 30% interest in the project. (in millions) Project Budget Actual Costs at September 30, 2021 Remaining Project Budget Construction Costs (1) $ 6,140 $ 5,342 $ 798 Financing Costs 1,778 1,443 335 Total Costs $ 7,918 $ 6,785 $ 1,133 Project-Level Contingency $ 90 $ — $ 90 Oglethorpe-Level Contingency 242 — 242 Total Contingency $ 332 $ — $ 332 Totals $ 8,250 $ 6,785 $ 1,465 (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement.

Plant Acquisition (Tables)

Plant Acquisition (Tables)	9 Months Ended
	Sep. 30, 2021
Business Combinations [Abstract]
Schedule of recognized identified assets acquired and liabilities assumed	The following amounts represent the identifiable assets acquired and liabilities assumed in the Effingham acquisition: Classification (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: Electric plant in service, net $ 229,215 Inventories, at average cost 3,264 Other current assets 3,167 Other current liabilities (2,490) Total identifiable net assets $ 233,156

General (Details)

General (Details)	9 Months Ended
	Sep. 30, 2021member
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of electric distribution cooperative members	38

Fair Value - Asset and liabilit

Fair Value - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($)	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Fair value
Nuclear decommissioning trust fund	$ 635,958,000	$ 598,181,000
Long-term investments	678,704,000	518,065,000
Natural gas swaps
Fair value
Derivative liabilities		10,248,000
International equity trust
Fair value
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Natural gas swaps
Fair value
Derivative liabilities	$ 93,930,000	10,248,000
Recurring basis | Domestic equity
Fair value
Nuclear decommissioning trust fund	225,255,000	198,325,000
Recurring basis | International equity trust
Fair value
Nuclear decommissioning trust fund	142,018,000	120,645,000
Long-term investments	35,015,000	31,378,000
Recurring basis | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	78,874,000	98,129,000
Long-term investments	15,590,000	29,870,000
Recurring basis | US Treasury securities
Fair value
Nuclear decommissioning trust fund	54,212,000	46,963,000
Long-term investments	13,440,000	7,437,000
Recurring basis | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	33,712,000	45,039,000
Long-term investments	11,582,000	11,432,000
Recurring basis | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	74,861,000	70,813,000
Long-term investments	271,354,000	224,536,000
Recurring basis | Municipal bonds
Fair value
Nuclear decommissioning trust fund	1,130,000	1,362,000
Recurring basis | Federal agency securities
Fair value
Nuclear decommissioning trust fund	9,792,000	6,054,000
Long-term investments	290,000	537,000
Recurring basis | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,696,000
Recurring basis | Treasury STRIPS
Fair value
Long-term investments	325,398,000	209,165,000
Recurring basis | Other
Fair value
Nuclear decommissioning trust fund	13,408,000	10,851,000
Long-term investments	6,035,000	3,710,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Natural gas swaps
Fair value
Derivative liabilities	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value
Nuclear decommissioning trust fund	225,255,000	198,325,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | International equity trust
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	54,212,000	46,963,000
Long-term investments	13,440,000	7,437,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	74,861,000	70,813,000
Long-term investments	271,354,000	224,536,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Treasury STRIPS
Fair value
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value
Nuclear decommissioning trust fund	13,408,000	7,720,000
Long-term investments	6,035,000	3,710,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value
Derivative liabilities	93,930,000	10,248,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Domestic equity
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value
Nuclear decommissioning trust fund	142,018,000	120,645,000
Long-term investments	35,015,000	31,378,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	78,306,000	97,788,000
Long-term investments	15,272,000	29,661,000
Recurring basis | Significant Other Observable Inputs (Level 2) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	33,712,000	45,039,000
Long-term investments	11,582,000	11,432,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	1,130,000	1,362,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	9,792,000	6,054,000
Long-term investments	290,000	537,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,696,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS
Fair value
Long-term investments	325,398,000	209,165,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Other
Fair value
Nuclear decommissioning trust fund	0	3,131,000
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Natural gas swaps
Fair value
Derivative liabilities	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Domestic equity
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | International equity trust
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	568,000	341,000
Long-term investments	318,000	209,000
Recurring basis | Significant Unobservable Inputs (Level 3) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Treasury STRIPS
Fair value
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Other
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	$ 0	$ 0

Fair Value - Estimated fair val

Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020
Carrying Value
Fair Value
Long-term debt	$ 10,700,098	$ 10,619,826
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value
Long-term debt	$ 12,568,831	$ 13,161,146

Derivative Instruments - Gas he

Derivative Instruments - Gas hedges (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions	9 Months Ended
	Sep. 30, 2021USD ($)MMBTU	Dec. 31, 2020USD ($)
Derivative Instruments
Derivative asset | $	$ 93,930
Derivative liabilities | $		$ 10,248
Collateral posted | $	$ 3,400
Notional volume of natural gas derivatives (in MMBTUs)	108.4
2021
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	4.4
2022
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	24.2
2023
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	23.8
2024
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	23.2
2025
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	19.9
2026
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	12.9

Derivative Instruments - Fair v

Derivative Instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020
Assets:
Fair value of assets	$ 93,930
Liabilities:
Fair value of liabilities		$ 10,248
Other current assets
Assets:
Fair value of assets	47,303	222
Other deferred charges
Assets:
Fair value of assets	46,627	0
Other current liabilities
Liabilities:
Fair value of liabilities	0	2,305
Other deferred credits
Liabilities:
Fair value of liabilities	$ 0	$ 8,165

Derivative Instruments - Realiz

Derivative Instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			$ 93,930		$ 10,248
Natural gas swaps | Regulatory asset
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			0		10,248
Natural gas swaps | Regulatory liability
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			93,930		$ 0
Natural gas swaps | Fuel
Gains and (losses) on derivative instruments
Gains	$ 15,831	$ 339	18,229	$ 339
Losses	0	(8,721)	(1,311)	(20,314)
Total	$ 15,831	$ (8,382)	$ 16,918	$ (19,975)

Investment Securities (Details)

Investment Securities (Details) - USD ($) $ in Thousands	9 Months Ended	12 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Cost
Equity	$ 300,141	$ 262,564
Debt	743,582	613,271
Other	19,444	11,431
Total	1,063,167	887,266
Gains
Equity	253,423	219,658
Debt	6,727	18,090
Other	0	0
Total	260,150	237,748
Losses
Equity	(4,727)	(8,127)
Debt	(3,928)	(641)
Other	0	0
Total	(8,655)	(8,768)
Fair Value
Equity	548,837	474,095
Debt	746,381	630,720
Other	19,444	11,431
Total	$ 1,314,662	$ 1,116,246

Revenue Recognition (Details)

Revenue Recognition (Details) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Sep. 30, 2021USD ($)memberservice	Sep. 30, 2020USD ($)	Dec. 31, 2020USD ($)
Revenue Recognition
Number of electric distribution cooperative members | member			38
Number of services provided | service			2
Member energy requirements supplied	65.00%	60.00%	61.00%	57.00%
Margins for interest ratio			1.10
Targeted margins for interest ratio			1.14
Refund liability	$ 16,500	$ 21,400	$ 16,500	$ 21,400
Operating revenues	460,822	366,239	1,195,280	1,038,857
Members
Revenue Recognition
Operating revenues	437,240	365,937	1,171,433	1,038,218
Receivables from contracts	156,095		156,095		$ 135,462
Non-Members
Revenue Recognition
Operating revenues	23,582	302	23,847	639
Receivables from contracts	6,562		6,562		$ 0
Capacity revenues | Members
Revenue Recognition
Operating revenues	228,048	222,187	716,303	721,836
Energy revenues | Members
Revenue Recognition
Operating revenues	209,192	143,750	455,130	316,382
Energy revenues | Non-Members
Revenue Recognition
Operating revenues	$ 23,582	$ 302	$ 23,847	$ 639

Revenue Recognition - Managemen

Revenue Recognition - Management Program (Details) - USD ($) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2018
Vogtle Units No. 3 & No. 4
Operating revenues
Amounts billed under rate management program	$ 11,601	$ 11,805
Cumulative recovery of financing costs	107,544
Vogtle New Units
Operating revenues
Cumulative recovery of financing costs	330,165
Rate management program, additional collection period			5 years
Rate management program, billing period			5 years
Amounts billed under additional rate management program	115,837	$ 93,390
Effingham County Power
Operating revenues
Cumulative recovery of financing costs	$ 191

Leases - Summary (Details)

Leases - Summary (Details)	9 Months Ended
	Sep. 30, 2021leaseoption
Minimum
Leases
Finance lease renewal term	1 year
Maximum
Leases
Finance lease renewal term	5 years
Lease terms through December 31, 2027
Leases
Number of finance leases	3
Lease terms through June 30, 2031
Leases
Number of finance leases	1
Lease terms through February 2042
Leases
Number of renewal options | option	1
Operating lease, renewal term	20 years
Scherer Unit No. 2
Leases
Percentage of undivided interest in Scherer Unit No. 2	60.00%
Number of finance leases	4

Leases - Balance Sheet Impact (

Leases - Balance Sheet Impact (Details) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020
Right-of-Use Assets—Finance leases
Right-of-use assets	$ 302,732	$ 302,732
Less: Accumulated provision for depreciation	(266,288)	(262,774)
Total finance lease assets	36,444	39,958
Lease liabilities—Finance leases
Obligations under finance leases	65,207	68,876
Long-term debt and finance leases due within one year	7,146	6,773
Total finance lease liabilities	$ 72,353	$ 75,649
Finance Lease, Liability, Current, Statement of Financial Position	Long-term debt and finance leases due within one year	Long-term debt and finance leases due within one year
Right-of-Use Assets—Operating leases
Electric plant in service	$ 2,540	$ 3,283
Total operating lease assets	2,540	3,283
Lease liabilities—Operating leases
Capitalization—Other	1,677	2,388
Other current liabilities	876	990
Total operating lease liabilities	$ 2,553	$ 3,378
Operating Lease, Liability, Current, Statement of Financial Position	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position	Obligation under Hydro Facility Transactions	Obligation under Hydro Facility Transactions

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Lease Cost
Amortization of leased assets	$ 1,693	$ 1,344	$ 4,726	$ 4,032
Interest on lease liabilities	2,045	2,217	6,133	6,651
Operating lease cost:	270	286	809	1,081
Total leased cost	$ 4,008	$ 3,847	$ 11,668	$ 11,764
Weighted-average remaining lease term (in years)
Finance leases	7 years 1 month 17 days		7 years 1 month 17 days		7 years 10 months 9 days
Operating leases	8 years 3 days		8 years 3 days		7 years 3 months 7 days
Weighted-average discount rate:
Finance leases	11.05%		11.05%		11.05%
Operating leases	4.76%		4.76%		4.63%

Leases - Other Lease Disclosure

Leases - Other Lease Disclosures (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2021	Sep. 30, 2020	Sep. 30, 2021	Sep. 30, 2020	Dec. 31, 2020
Lessee
Operating cash flows from finance leases			$ 4,180	$ 4,516
Operating cash flows from operating leases			890	1,301
Financing cash flows from finance leases			3,295	2,959
Right-of-use assets obtained in exchange for new operating lease liabilities			0	0
Finance Leases
2021	$ 7,474		7,474
2022	14,949		14,949
2023	14,949		14,949
2024	14,949		14,949
2025	14,949		14,949
Thereafter	40,582		40,582
Total lease payments	107,852		107,852
Less: imputed interest	(35,499)		(35,499)
Total finance lease liabilities	72,353		72,353		$ 75,649
Operating Leases
2021	230		230
2022	929		929
2023	708		708
2024	234		234
2025	72		72
Thereafter	1,011		1,011
Total lease payments	3,184		3,184
Less: imputed interest	(631)		(631)
Total operating lease liabilities	2,553		2,553		$ 3,378
Total
2021	7,704		7,704
2022	15,878		15,878
2023	15,657		15,657
2024	15,183		15,183
2025	15,021		15,021
Thereafter	41,593		41,593
Total lease payments	111,036		111,036
Less: imputed interest	(36,130)		(36,130)
Present value of lease liabilities	74,906		74,906
Lessor
Lease income	$ 1,603	$ 1,543	$ 4,806	$ 4,633

Restricted Cash and Investmen_3

Restricted Cash and Investments (Details) $ in Thousands	Oct. 01, 2021	Oct. 01, 2020	Sep. 30, 2021USD ($)	Dec. 31, 2020USD ($)
Restricted Cash and Cash Equivalents Items [Line Items]
Guaranteed interest rate on deposit (as a percent)		0.04
Restricted investments			$ 319,980	$ 487,587
Restricted investments, long-term			$ 73,400	$ 306,601
Subsequent Event
Restricted Cash and Cash Equivalents Items [Line Items]
Guaranteed interest rate on deposit (as a percent)	0.0009

Restricted Cash and Investmen_4

Restricted Cash and Investments - Reconciliation of cash, cash equivalents and restricted cash (Details) - USD ($) $ in Thousands	Sep. 30, 2021	Dec. 31, 2020	Sep. 30, 2020	Dec. 31, 2019
Restricted Investments Note [Abstract]
Cash and cash equivalents	$ 452,943	$ 405,511	$ 383,868
Restricted cash included in Prepayments and other current assets	3,400		0
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$ 456,343	$ 405,511	$ 383,868	$ 448,612

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2021	Dec. 31, 2020
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 898,117	$ 731,438
Total Regulatory Liabilities	816,229	566,399
Net Regulatory Assets	81,888	165,039
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	21,124	20,054
Deferral of effects on net margin | Hawk Road Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	17,407	17,869
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	61,127	39,776
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	9,182	11,356
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	134,833	123,772
Asset retirement obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	142,368	130,901
Revenue deferral plan
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 334,645	220,111
Amortization Period	5 years
Natural gas hedges
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 93,930	0
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 1,613	2,560
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization Period	6 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 34,307	35,433
Premium and loss on reacquired debt | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	22 years
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 34,555	35,328
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 36,734	35,232
Coal-fired maintenance outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	60 months
Nuclear refueling outage costs | Minimum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	18 months
Nuclear refueling outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	24 months
Asset retirement obligations | Ashpond and other
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 272,923	242,832
Depreciation expense | Other
Regulatory Assets and Liabilities
Total Regulatory Assets	37,329	38,396
Depreciation expense | Plant Wansley
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 149,641	0
Depreciation expense | Plant Vogtle
Regulatory Assets and Liabilities
Operating license expected extension period for Plant Vogtle	20 years
Operating license period	40 years
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units No. 3 & No. 4
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 55,702	55,430
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	130,367	126,813
Deferral of effects on net margin - Smith Energy Facility | Smith Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Assets	144,161	148,620
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 2,398	$ 13,354
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	29 years

Debt - Department of Energy Loa

Debt - Department of Energy Loan Guarantee (Details)	9 Months Ended
	Sep. 30, 2021USD ($)	Sep. 30, 2020USD ($)	Mar. 22, 2019USD ($)	Dec. 31, 2017USD ($)	Feb. 20, 2014USD ($)note
Debt
Repayments of long-term debt	$ 440,548,000	$ 1,274,196,000
Vogtle Units No. 3 & No. 4
Debt
Guarantee payment				$ 1,104,000,000
Loan Guarantee Agreement
Debt
Term of debt	5 years
Period of cessation of construction activities which would result in prepayment of outstanding principal	12 months
Period of failure to fund operation and maintenance expenses which would result in prepayment of outstanding principal	12 months
Long-term debt
Debt
Ownership interests voting required to continue construction (as a percent)	90.00%
Long-term debt | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 3,880,348,382
Long-term debt | FFB
Debt
Number of future advance promissory notes | note					2
Maximum borrowing capacity			$ 1,619,679,706		$ 3,057,069,461
Capitalized interest					335,471,604
Maximum borrowing capacity designated for capitalized interest					$ 43,721,079
Eligible project costs, percent			70.00%
Repayments of long-term debt	158,313,000
Long-term debt | FFB | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 867,000,000
Long-term debt | FFB | Department of Energy guarantee | Services Agreement
Debt
Guarantee payment			$ 4,676,749,167
Long-term debt | FFB | US Treasury Securities, Current Yield
Debt
Spread on variable rate (as a percent)	0.375%

Debt - Rural Utilities Service

Debt - Rural Utilities Service Guaranteed Loans (Details) - Long-term debt - FFB - Rural Utilities Service Guaranteed Loans - USD ($) $ in Thousands	1 Months Ended	9 Months Ended
	Oct. 31, 2021	Sep. 30, 2021
Debt
Advances received on loans		$ 270,524
Subsequent Event
Debt
Advances received on loans	$ 12,508

Debt - Bonds (Details)

Debt - Bonds (Details) $ in Thousands	1 Months Ended
	Aug. 31, 2021USD ($)
Municipal bonds | Series 2009 and 2010 Pollution Control Revenue Bonds
Debt
Repayments of pollution control bond	$ 245,605

Debt - Lines of Credit (Details

Debt - Lines of Credit (Details) - Line of Credit - JPMorgan Chase - USD ($) $ in Millions	Oct. 01, 2021	Sep. 30, 2021
Debt
Maximum borrowing capacity		$ 363
Subsequent Event
Debt
Maximum borrowing capacity	$ 350

Vogtle Units No. 3 and No. 4 _3

Vogtle Units No. 3 and No. 4 Construction Project - Narrative (Details) $ in Millions	Feb. 18, 2019USD ($)	Sep. 30, 2021USD ($)	Jun. 30, 2021USD ($)	Mar. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Sep. 30, 2021USD ($)unit	Dec. 31, 2008unitMW
Vogtle Units No. 3 & No. 4
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30.00%				30.00%
Total investment in additional Vogtle units		$ 6,800				$ 6,800
Additional construction contingency, total		300	$ 260	$ 106	$ 375
Project-Level Contingency		90	78	32	$ 112.5
Additional construction contingency, construction productivity and field support		278	746	183
Ownership amount of additional construction contingency, construction productivity and field support		$ 83	224	$ 55
Project level contingency			300
Ownership amount of project level contingency			$ 90
Monthly delay cost						55
Total project costs						17,100
Total budget revisions						$ 2,400
Vogtle Units No. 3 & No. 4 | Financial Exposure Term One
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30.00%				30.00%
Vogtle Units No. 3 & No. 4 | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30.00%				30.00%
Vogtle Units No. 3 & No. 4 | Minimum
Public Utility Property Plant and Equipment
COVID related costs						$ 350
Ownership amount of COVID related costs						105
Vogtle Units No. 3 & No. 4 | Maximum
Public Utility Property Plant and Equipment
COVID related costs						438
Ownership amount of COVID related costs						$ 131
Vogtle Units No. 3 & No. 4 | Ownership participation agreement
Public Utility Property Plant and Equipment
Number of additional nuclear units | unit						2
Ownership interest (as a percent)		30.00%				30.00%
Project budget						$ 8,250
Vogtle Units No. 3 & No. 4 | EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Public Utility Property Plant and Equipment
Number of nuclear units | unit							2
Generating capacity of each nuclear unit (in megawatts) | MW							1,100
Vogtle Units No. 3 & No. 4 | Services Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Public Utility Property Plant and Equipment
Written notice period for termination of agreement						30 days
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet
Public Utility Property Plant and Equipment
Project budget	$ 8,400
Construction contingency estimate	$ 800
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term One
Public Utility Property Plant and Equipment
Proportionate share of construction costs, Co-Owner	55.70%
Proportionate share of additional construction costs, Co-Owner	$ 80
Proportionate share of additional construction costs	$ 44
Proportionate share of construction costs, remaining co-owners	44.30%
Proportionate share of construction costs	24.50%
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Proportionate share of construction costs, Co-Owner	65.70%
Proportionate share of additional construction costs, Co-Owner	$ 100
Proportionate share of additional construction costs	$ 55
Proportionate share of construction costs, remaining co-owners	34.30%
Proportionate share of construction costs	19.00%
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term Three
Public Utility Property Plant and Equipment
Additional construction costs that triggers option to tender ownership	$ 2,100
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum
Public Utility Property Plant and Equipment
Percentage of ownership approval to change primary construction contractor		90.00%				90.00%
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term One
Public Utility Property Plant and Equipment
Construction contingency estimate	800
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Construction contingency estimate	$ 1,600
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term Three
Public Utility Property Plant and Equipment
One time option to tender portion of ownership, exercise period	120 days
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term One
Public Utility Property Plant and Equipment
Construction contingency estimate	$ 1,600
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Construction contingency estimate	$ 2,100
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term Three
Public Utility Property Plant and Equipment
One time option to tender portion of ownership, exercise period	180 days
Vogtle Unit Number 4
Public Utility Property Plant and Equipment
Monthly delay cost						$ 25

Vogtle Units No. 3 and No. 4 _4

Vogtle Units No. 3 and No. 4 Construction Project - Project Budget and Actual Costs (Details) - Vogtle Units No. 3 & No. 4 - USD ($) $ in Millions	3 Months Ended				9 Months Ended
	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2021
Project Budget
Project-Level Contingency	$ 90	$ 78	$ 32	$ 112.5
Actual Costs
Totals					$ 17,100
Remaining Project Budget
Proceeds from guarantee agreement					1,100
Jointly Owned Nuclear Power Plant
Project Budget
Construction Costs					6,140
Financing Costs					1,778
Total Costs					7,918
Project-Level Contingency					90
Oglethorpe-Level Contingency					242
Total Contingency					332
Totals					8,250
Actual Costs
Construction Costs					5,342
Financing Costs					1,443
Total Costs					6,785
Project-Level Contingency					0
Oglethorpe-Level Contingency					0
Total Contingency					0
Totals					6,785
Remaining Project Budget
Construction Costs					798
Financing Costs					335
Total Costs					1,133
Project-Level Contingency					90
Oglethorpe-Level Contingency					242
Total Contingency					332
Totals					$ 1,465

Plant Acquisition - Narrative (

Plant Acquisition - Narrative (Details) - Effingham County Power - Natural Gas Processing Plant $ in Thousands	Jul. 08, 2021USD ($)MW	Sep. 30, 2021
Plant Acquisition [Line Items]
Generating capacity of each nuclear unit (in megawatts) | MW	511
Purchase price	$ 233,156
Acquisition costs	$ 1,382
Amortization period, regulatory asset		22 years

Plant Acquisition - Identifiabl

Plant Acquisition - Identifiable Assets Acquired and Liabilities Assumed (Details) - Effingham County Power - Natural Gas Processing Plant $ in Thousands	Jul. 08, 2021USD ($)
Plant Acquisition [Line Items]
Electric plant in service, net	$ 229,215
Inventories, at average cost	3,264
Other current assets	3,167
Other current liabilities	(2,490)
Total identifiable net assets	$ 233,156