Oglethorpe Power 10-Q 11 Aug 22 2022 Q2 Quarterly report Financial data

Cover Page

Cover Page	6 Months Ended
	Jun. 30, 2022 shares
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
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	No
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	2022
Document Fiscal Period Focus	Q2

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Electric plant:
In service	$ 9,906,904	$ 9,865,660
Right-of-use assets—finance leases	302,732	302,732
Less: Accumulated provision for depreciation	(5,782,319)	(5,565,724)
Net in service	4,427,317	4,602,668
Nuclear fuel, at amortized cost	378,263	375,267
Construction work in progress	7,230,565	6,779,392
Total electric plant	12,036,145	11,757,327
Investments and funds:
Nuclear decommissioning trust fund	535,714	659,910
Investment in associated companies	77,409	75,826
Long-term investments	648,297	711,379
Restricted investments	0	73,702
Bond purchase fund	30,975	0
Other	32,873	31,991
Total investments and funds	1,325,268	1,552,808
Current assets:
Cash and cash equivalents	476,792	579,350
Restricted cash and short-term investments	219,840	248,150
Short-term investments	42,691	0
Receivables	274,809	159,538
Inventories, at average cost	282,563	260,526
Prepayments and other current assets	122,121	60,486
Total current assets	1,418,816	1,308,050
Deferred charges and other assets:
Regulatory assets	1,148,041	1,008,790
Prepayments to Georgia Power Company	22,672	27,124
Other	134,686	52,927
Total deferred charges	1,305,399	1,088,841
Total assets	16,085,628	15,707,026
Capitalization:
Patronage capital and membership fees	1,170,570	1,130,423
Long-term debt	11,053,441	10,529,449
Obligation under finance leases	57,249	61,335
Other	28,245	27,701
Total capitalization	12,309,505	11,748,908
Current liabilities:
Long-term debt and finance leases due within one year	292,343	281,238
Short-term borrowings	761,282	1,095,971
Accounts payable	243,063	182,164
Accrued interest	80,157	96,410
Member power bill prepayments, current	34,584	26,102
Other current liabilities	143,110	36,123
Total current liabilities	1,554,539	1,718,008
Deferred credits and other liabilities:
Asset retirement obligations	1,310,412	1,287,143
Member power bill prepayments, non-current	59,041	80,001
Regulatory liabilities	829,250	849,449
Other	22,881	23,517
Total deferred credits and other liabilities	2,221,584	2,240,110
Total equity and liabilities	$ 16,085,628	$ 15,707,026

Consolidated Statements of Reve

Consolidated Statements of Revenues and Expenses (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Operating revenues:
Total operating revenues	$ 533,128	$ 358,127	$ 953,570	$ 734,458
Operating expenses:
Fuel	263,121	113,531	428,605	221,596
Production	113,387	93,477	209,167	198,850
Depreciation and amortization	70,830	67,277	141,756	134,896
Purchased power	17,661	16,866	34,536	33,786
Accretion	13,860	13,941	27,392	27,722
Total operating expenses	478,859	305,092	841,456	616,850
Operating margin	54,269	53,035	112,114	117,608
Other income:
Investment income	12,825	12,130	24,672	24,090
Other	3,095	277	6,125	2,448
Total other income	15,920	12,407	30,797	26,538
Interest charges:
Interest expense	111,595	104,247	216,264	207,726
Allowance for debt funds used during construction	(62,497)	(54,810)	(119,270)	(108,449)
Amortization of debt discount and expense	2,924	2,860	5,770	5,766
Net interest charges	52,022	52,297	102,764	105,043
Net margin	18,167	13,145	40,147	39,103
Members
Operating revenues:
Total operating revenues	478,782	357,921	896,231	734,193
Non-Members
Operating revenues:
Total operating revenues	$ 54,346	$ 206	$ 57,339	$ 265

Consolidated Statements of Patr

Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2022	Jun. 30, 2021
Increase (Decrease) in Members' Capital
Net margin	$ 18,167		$ 13,145		$ 40,147	$ 39,103
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Beginning balance	1,152,403	$ 1,130,423	1,098,600	$ 1,072,642	1,130,423	1,072,642
Net margin	18,167	21,980	13,145	25,958
Ending balance	$ 1,170,570	$ 1,152,403	$ 1,111,745	$ 1,098,600	$ 1,170,570	$ 1,111,745

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Cash flows from operating activities:
Net margin	$ 40,147	$ 39,103
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	203,299	199,649
Accretion cost	27,392	27,722
Amortization of deferred gains	(894)	(894)
Allowance for equity funds used during construction	(291)	(138)
Deferred outage costs	(23,107)	(16,581)
Loss (gain) on sale of investments	18,467	(10,284)
Regulatory deferral of costs associated with nuclear decommissioning	(33,956)	(7,626)
Other	642	(698)
Change in operating assets and liabilities:
Receivables	(123,344)	(31,535)
Inventories	(21,933)	13,759
Prepayments and other current assets	(20,532)	5,349
Accounts payable	17,584	(32,833)
Accrued interest	(16,253)	1,619
Accrued taxes	35,915	(8,147)
Other current liabilities	64,929	(8,928)
Member power bill prepayments	(12,478)	(19,182)
Rate management program collections, net	13,960	78,524
Total adjustments	129,400	189,776
Net cash provided by operating activities	169,547	228,879
Cash flows from investing activities:
Property additions	(526,406)	(603,062)
Activity in nuclear decommissioning trust fund—Purchases	(199,140)	(374,059)
Activity in nuclear decommissioning trust fund - Proceeds	195,557	370,145
Increase in restricted cash and investments	184,812	109,302
Activity in other long-term investments—Purchases	(134,310)	(227,706)
Activity in other long-term investments - Proceeds	102,982	129,594
Other	2,615	8,663
Net cash used in investing activities	(373,890)	(587,123)
Cash flows from financing activities:
Long-term debt proceeds	792,503	503,431
Long-term debt payments	(256,747)	(123,520)
(Decrease) increase in short-term borrowings, net	(334,689)	206,467
Other	14,493	11,511
Net cash provided by financing activities	215,560	597,889
Net increase in cash, cash equivalents and restricted cash	11,217	239,645
Cash, cash equivalents and restricted cash at beginning of period	581,150	405,511
Cash, cash equivalents and restricted cash at end of period	592,367	645,156
Cash paid for—
Interest (net of amounts capitalized)	112,365	96,832
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	0	(399)
Accrued property additions at end of period	64,476	70,537
Bond purchase fund included in cash and cash equivalents at end of period	$ 30,975	$ 245,605

General

General	6 Months Ended
	Jun. 30, 2022
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 six-month periods ended June 30, 2022 and 2021. 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. Certain prior year amounts have been reclassified to conform with current year presentation.

Fair Value

Fair Value	6 Months Ended
	Jun. 30, 2022
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 of comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2022 and December 31, 2021. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs June 30, 2022 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 199,520 $ 199,520 $ — $ — International equity trust 109,140 — 109,140 — Corporate bonds and debt 86,470 — 86,470 — US Treasury securities 41,590 41,590 — — Mortgage backed securities 24,902 — 24,902 — Domestic mutual funds 54,219 54,219 — — Federal agency securities 3,138 — 3,138 — Non-US Gov't bonds & private placements 2,988 — 2,988 — Other 13,747 13,747 — — Long-term investments: International equity trust 32,940 — 32,940 — Corporate bonds and debt 19,749 — 19,749 — US Treasury securities 157 157 — — Mortgage backed securities 10,976 — 10,976 — Domestic mutual funds 264,867 264,867 — — Treasury STRIPS 308,949 — 308,949 — Non-US Gov't bonds & private placements 1,441 — 1,441 — Other 9,218 9,218 — — Short-term investments: Treasury STRIPS 42,691 — 42,691 — Natural gas swaps 184,859 — 184,859 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2021 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 249,999 $ 249,999 $ — $ — International equity trust 140,718 — 140,718 — Corporate bonds and debt 72,936 — 72,369 567 US Treasury securities 53,321 53,321 — — Mortgage backed securities 40,460 — 40,460 — Domestic mutual funds 75,384 75,384 — — Municipal bonds 1,133 — 1,133 — Federal agency securities 9,608 — 9,608 — Other 16,351 13,623 2,728 — Long-term investments: International equity trust 35,873 — 35,873 — Corporate bonds and debt 14,022 — 12,656 1,366 US Treasury securities 15,259 15,259 — — Mortgage backed securities 12,021 — 12,021 — Domestic mutual funds 277,937 277,937 — — Federal agency securities 257 — 257 — Treasury STRIPS 350,532 — 350,532 — Other 5,478 5,478 — — Natural gas swaps 63,994 — 63,994 — 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 June 30, 2022 and December 31, 2021 were as follows: 2022 2021 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 11,454,480 $ 10,704,745 $ 10,915,054 $ 12,741,046 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 June 30, 2022 and December 31, 2021 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	6 Months Ended
	Jun. 30, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments. We use commodity 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 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 June 30, 2022, all of the counterparties with transaction amounts outstanding under our derivative 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 derivative 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 June 30, 2022 and December 31, 2021, the estimated fair values of our natural gas contracts were net assets of approximately $184,859,000 and $63,994,000, respectively. As of June 30, 2022, three of our counterparties were required to post credit collateral totaling $84,600,000 under our natural gas swap agreements. As of December 31, 2021, one of our counterparties was required to post credit collateral totaling $1,800,000 under our natural gas swap agreements. Such posted collateral is classified as restricted cash and included in the Restricted cash and short-term investments line items within our unaudited consolidated balance sheets. The following table reflects the notional volume of our natural gas derivatives as of June 30, 2022 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2022 14.7 2023 27.9 2024 25.7 2025 22.2 2026 16.9 2027 3.5 Total 110.9 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2022 and December 31, 2021. Balance Sheet Location Fair Value 2022 2021 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 60,849 $ 23,596 Natural gas swaps Other deferred charges $ 126,283 $ 40,398 Liabilities: Natural gas swaps Other current liabilities $ 2,273 $ — Natural gas swaps Other deferred credits $ — $ — The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and six months ended June 30, 2022 and 2021. Statement of Three Months Ended Six Months Ended June 30, 2022 2021 2022 2021 (dollars in thousands) Natural gas swaps gains Fuel $ 42,563 $ 2,297 $ 50,641 $ 2,398 Natural gas swaps losses Fuel (203) (67) (282) (1,311) Total $ 42,360 $ 2,230 $ 50,359 $ 1,087 The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at June 30, 2022 and December 31, 2021. Balance Sheet Location 2022 2021 (dollars in thousands) Natural gas swaps Regulatory liability $ 184,859 $ 63,994 Total $ 184,859 $ 63,994

Investments Securities

Investments Securities	6 Months Ended
	Jun. 30, 2022
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 as of June 30, 2022 and December 31, 2021. Gross Unrealized (dollars in thousands) June 30, 2022 Cost Gains Losses Fair Equity $ 312,999 $ 150,402 $ (6,975) $ 456,426 Debt 801,320 349 (32,819) 768,850 Other 1,426 — — 1,426 Total $ 1,115,745 $ 150,751 $ (39,794) $ 1,226,702 Gross Unrealized (dollars in thousands) December 31, 2021 Cost Gains Losses Fair Equity $ 304,305 $ 280,127 $ (4,682) $ 579,750 Debt 774,580 4,859 (7,001) 772,438 Other 19,102 — (1) 19,101 Total $ 1,097,987 $ 284,986 $ (11,684) $ 1,371,289

Recently Issued or Adopted Acco

Recently Issued or Adopted Accounting Pronouncements	6 Months Ended
	Jun. 30, 2022
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 have fully completed our evaluation of this new standard and we do not expect this standard will have a material impact on our consolidated financial statements.

Revenue Recognition

Revenue Recognition	6 Months Ended
	Jun. 30, 2022
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. 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. As of June 30, 2022 and December 31, 2021, we did not have any long-term contracts with non-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 six-month periods ended June 30, 2022 and 2021, we provided approximately 58% and 59% 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 2022, 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 unaudited consolidated balance sheets. As of June 30, 2022 and June 30, 2021, we recognized refund liabilities totaling $5,000,000 and $4,500,000, 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 six months ended June 30, 2022 and 2021 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2022 2021 2022 2021 Capacity revenues $ 241,841 $ 232,431 $ 485,132 $ 488,255 Energy revenues 236,941 125,490 411,099 245,938 Total $ 478,782 $ 357,921 $ 896,231 $ 734,193 Member energy requirements supplied 59 % 62 % 58 % 59 % Receivables from contracts with our members at June 30, 2022 and December 31, 2021 were $218,953,000 and $143,715,000, respectively. Sales to non-members during the three and six months ended June 30, 2022 and 2021 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2022 2021 2022 2021 Energy revenues $ 54,346 $ 206 $ 57,339 $ 265 Receivables from non-member energy sales at June 30, 2022 and December 31, 2021 were $21,235,000 and $302,000, respectively. Energy revenues from non-members for the three and six months ended June 30, 2022 were primarily from the sale of a portion of the energy output at Effingham, which we acquired in July 2021, into the wholesale market. For additional information regarding the Effingham acquisition, see Note 13 in our 2021 Form 10-K. There were no capacity revenues from non-members for the three and six months ended June 30, 2022 and 2021. 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 and have not had a history of any write-offs from 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 associated with the construction of Vogtle Units No. 3 and No. 4, 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. Under this program, amounts billed to participating members during the six months ended June 30, 2022 and 2021 were $9,440,000 and $7,729,000, respectively. The cumulative amount billed since inception of the program totaled $121,076,000.

Leases

Leases	6 Months Ended
	Jun. 30, 2022
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 six months ended June 30, 2022 and 2021 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. 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 June 30, 2022 December 31, 2021 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (270,241) (267,606) Total finance lease assets $ 32,491 $ 35,126 Lease liabilities—Finance leases Obligations under finance leases $ 57,249 $ 61,335 Long-term debt and finance leases due within one year 7,958 7,541 Total finance lease liabilities $ 65,207 $ 68,876 Classification June 30, 2022 December 31, 2021 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service, net $ 1,876 $ 2,293 Total operating lease assets $ 1,876 $ 2,293 Lease liabilities—Operating leases Capitalization—Other $ 1,212 $ 1,550 Other current liabilities 758 838 Total operating lease liabilities $ 1,970 $ 2,388 Three months ended Six months ended Lease Cost Classification June 30, 2022 June 30, 2021 June 30, 2022 June 30, 2021 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,886 $ 1,517 $ 3,771 $ 3,033 Interest on lease liabilities Interest expense 1,852 2,044 3,704 4,088 Operating lease cost: Inventory (1) & production expense 222 269 444 539 Total leased cost $ 3,960 $ 3,830 $ 7,919 $ 7,660 (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. June 30, 2022 December 31, 2021 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 6.42 6.90 Operating leases 8.83 8.01 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.83 % 4.73 % Six months ended June 30, 2022 2021 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,806 $ 4,180 Operating cash flows from operating leases $ 444 $ 539 Financing cash flows from finance leases $ 3,669 $ 3,295 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of June 30, 2022 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2022 $ 7,475 $ 485 $ 7,960 2023 14,949 708 15,657 2024 14,949 234 15,183 2025 14,949 72 15,021 2026 14,949 72 15,021 Thereafter 25,634 940 26,574 Total lease payments $ 92,905 $ 2,511 $ 95,416 Less: imputed interest (27,698) (541) (28,239) Present value of lease liabilities $ 65,207 $ 1,970 $ 67,177 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 six months ended June 30, 2022 and 2021 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 (dollars in thousands) Lease income $ 1,669 $ 1,606 $ 3,314 $ 3,203
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 six months ended June 30, 2022 and 2021 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. 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 June 30, 2022 December 31, 2021 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (270,241) (267,606) Total finance lease assets $ 32,491 $ 35,126 Lease liabilities—Finance leases Obligations under finance leases $ 57,249 $ 61,335 Long-term debt and finance leases due within one year 7,958 7,541 Total finance lease liabilities $ 65,207 $ 68,876 Classification June 30, 2022 December 31, 2021 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service, net $ 1,876 $ 2,293 Total operating lease assets $ 1,876 $ 2,293 Lease liabilities—Operating leases Capitalization—Other $ 1,212 $ 1,550 Other current liabilities 758 838 Total operating lease liabilities $ 1,970 $ 2,388 Three months ended Six months ended Lease Cost Classification June 30, 2022 June 30, 2021 June 30, 2022 June 30, 2021 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,886 $ 1,517 $ 3,771 $ 3,033 Interest on lease liabilities Interest expense 1,852 2,044 3,704 4,088 Operating lease cost: Inventory (1) & production expense 222 269 444 539 Total leased cost $ 3,960 $ 3,830 $ 7,919 $ 7,660 (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. June 30, 2022 December 31, 2021 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 6.42 6.90 Operating leases 8.83 8.01 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.83 % 4.73 % Six months ended June 30, 2022 2021 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,806 $ 4,180 Operating cash flows from operating leases $ 444 $ 539 Financing cash flows from finance leases $ 3,669 $ 3,295 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of June 30, 2022 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2022 $ 7,475 $ 485 $ 7,960 2023 14,949 708 15,657 2024 14,949 234 15,183 2025 14,949 72 15,021 2026 14,949 72 15,021 Thereafter 25,634 940 26,574 Total lease payments $ 92,905 $ 2,511 $ 95,416 Less: imputed interest (27,698) (541) (28,239) Present value of lease liabilities $ 65,207 $ 1,970 $ 67,177 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 six months ended June 30, 2022 and 2021 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 (dollars in thousands) Lease income $ 1,669 $ 1,606 $ 3,314 $ 3,203

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	6 Months Ended
	Jun. 30, 2022
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. In July 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 groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia Power has filed multiple motions to dismiss the complaint. On October 8, 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer, have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. On November 11, 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. On March 9, 2022, Georgia Power filed notices to remove the four additional cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. Collectively, these cases include approximately 70 plaintiffs. The amount of any possible losses from these matters cannot be estimated at this time. In May 2022, Florida Power & Light Company and JEA filed a complaint in the U.S. District Court for the Northern District of Georgia against us and the other co-owners of Plant Scherer alleging that their contractual responsibility for a proportionate share of certain common facility costs relating to future environmental projects at Plant Scherer should be decreased following the retirement of Scherer Unit No. 4 at the end of 2021. We and the other co-owners of Plant Scherer have filed motions to dismiss Florida Power & Light and JEA's complaint. While we do not believe that the co-ownership agreements support the arguments raised by Florida Power & Light Company and JEA, if their arguments were to be successful in this case, we could be responsible for an increased percentage of these costs relating to our interests in Scherer Unit Nos. 1 and 2. The amount of additional costs relating to these future projects, if any, cannot be determined at this time.

Restricted Cash and Investments

Restricted Cash and Investments	6 Months Ended
	Jun. 30, 2022
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. For the period from January 1, 2021 to September 30, 2021, 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 be reset annually on October 1 of each year thereafter. The program no longer allows additional funds to be deposited into the account. At June 30, 2022 and December 31, 2021, we had restricted investments totaling $135,195,000 and $320,052,000, respectively, of which $135,195,000 and $246,350,000, respectively, were classified as current. Restricted cash consists of collateral posted by our counterparties under our natural gas swap agreements. 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 June 30, 2022 June 30, 2021 (dollars in thousands) Cash and cash equivalents $ 476,792 $ 399,551 Bond purchase fund 30,975 245,605 Restricted cash included in restricted cash and short-term investments 84,600 — Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 592,367 $ 645,156

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	6 Months Ended
	Jun. 30, 2022
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 consolidated balance sheets as of June 30, 2022 and December 31, 2021. 2022 2021 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 31,199 $ 33,200 Amortization of financing leases(b) 33,043 34,179 Outage costs(c) 38,323 31,956 Asset retirement obligations—Ashpond and other(l) 343,197 335,231 Asset retirement obligations—Nuclear(l) 13,105 — Depreciation expense - Plant Vogtle(d) 36,261 36,973 Depreciation expense - Plant Wansley(e) 316,034 204,891 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,442 55,857 Interest rate options cost(g) 134,018 131,556 Deferral of effects on net margin—Smith Energy Facility(h) 139,702 142,675 Other regulatory assets(o) 7,717 2,272 Total Regulatory Assets $ 1,148,041 $ 1,008,790 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 22,871 $ 22,197 Deferral of effects on net margin—Hawk Road Energy Facility(h) 16,945 17,253 Deferral of effects on net margin—Effingham Energy Facility(p) 4,387 — Major maintenance reserve(j) 90,410 73,059 Amortization of financing leases(b) 7,007 8,457 Deferred debt service adder(k) 146,716 138,897 Asset retirement obligations—Nuclear(l) — 164,256 Revenue deferral plan(m) 354,673 359,799 Natural gas hedges(n) 184,859 63,994 Other regulatory liabilities(o) 1,382 1,537 Total Regulatory Liabilities $ 829,250 $ 849,449 Net Regulatory Assets $ 318,791 $ 159,341 (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 by the end of August 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, per each members' election, over the subsequent five-year period. (n) Represents the deferral of unrealized gains on natural gas hedges. (o) The amortization periods for other regulatory assets range up to 28 years and the amortization periods of other regulatory liabilities range up to 5 years. (p) Effects on net margin for the Effingham Energy Facility that are being deferred until on or before January 2026 and will be amortized over the remaining life of the plant.

Member Power Bill Prepayments

Member Power Bill Prepayments	6 Months Ended
	Jun. 30, 2022
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	6 Months Ended
	Jun. 30, 2022
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 June 30, 2022, borrowings under the Additional FFB Note totaled $1,262,000,000. At June 30, 2022, aggregate Department of Energy-guaranteed borrowings, including capitalized interest, totaled $4,275,348,382. 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 June 30, 2022, we have repaid $243,505,000 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%. 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 six-month period ended June 30, 2022, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $52,503,000 for long-term financing of general and environmental improvements at existing plants. In July 2022, we received an additional $10,528,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) First Mortgage Bonds: On April 12, 2022, we issued $500,000,000 of 4.50% first mortgage bonds, Series 2022A, for the purpose of providing long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. In conjunction with the issuance of the bonds, we repaid $493,405,000 of outstanding commercial paper. The bonds are due to mature April 2047 and are secured under our first mortgage indenture. d) Pollution Control Revenue Bonds: We intend to redeem $31.0 million of Series 2017 pollution control revenue bonds in the third quarter of 2022. At June 30, 2022, these bonds were classified as long-term debt based upon the contractual maturity date. Cash and cash equivalents designated to redeem the bonds were classified as a non-current asset within the bond purchase fund line item of the unaudited consolidated balance sheets. Total cash and cash equivalents of $592,367,000, as shown on our

Vogtle Units No. 3 and No. 4 Co

Vogtle Units No. 3 and No. 4 Construction Project	6 Months Ended
	Jun. 30, 2022
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 (MEAG), 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. 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) and is reimbursed for actual costs plus a base fee and an at-risk fee, 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. Cost and Schedule Our current budget for our ownership interest in Vogtle Units No. 3 and No. 4, which includes capital costs, allowance for funds used during construction and some level of contingency is $8.1 billion and is based on commercial operation dates of March 2023 and March 2024 for Units No. 3 and No. 4, respectively. This budget reflects our June 17, 2022 exercise of the tender option in the Global Amendments to the Joint Ownership Agreements as described below. Had we not exercised the tender option, our budget would be approximately $8.6 billion. At June 30, 2022, our total investment for our interest in the additional Vogtle units was approximately $7.5 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. Our initial ownership interest and proportionate share of the cost to construct the additional Vogtle units was 30%, representing approximately 660 megawatts. However, we have exercised the tender option discussed below which caps our capital costs in exchange for a proportionate reduction of our 30% interest in the two units. Based on the current project budget and schedule and our interpretation of the Global Amendments (described below), we would transfer approximately 50 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share would decline from 30% to approximately 28%. However, if the total project budget exceeds the current budget, our ownership share and megawatts would be further reduced. 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. 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 June 30, 2022 for our share of the project. (in millions) Project Budget (Tender) Actual Costs at Construction Costs (1) $ 6,021 $ 5,842 Financing Costs 1,966 1,626 Subtotal $ 7,987 $ 7,468 Deferred Training Costs 54 46 Total Project Costs Before Contingency $ 8,041 $ 7,514 Oglethorpe-Level Contingency 59 — Total Contingency $ 59 $ — Totals $ 8,100 $ 7,514 (1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements. Any schedule extension beyond March 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $30 million per month for both units and approximately $13 million per month for Unit No. 4. 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. Since March 2020, the number of active cases of COVID-19 at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion. COVID-19 has exacerbated the challenges facing the project, 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. As of June 30, 2022, the incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity, substantially all of which occurred during 2020 and 2021, is estimated by Georgia Power to be between $350 million and $438 million and is included in the project budget. Subsequent waves 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 Unit No. 3 projected schedule primarily depends on pace of system and area turnovers, timing of fuel load and the progression of startup and other testing. On August 3, 2022, the Nuclear Regulatory Commission approved Southern Nuclear’s 103(G) letter for Unit No. 3 which was the final Nuclear Regulatory Commission finding necessary for Southern Nuclear to begin fuel load and start-up sequence. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 during the first quarter of 2023. Our current budget reflects our expectation of an in-service date for Unit No. 3 in March 2023. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 during the fourth quarter 2023. Given the remaining work to be done and potential risks associated with completing the work, our current budget anticipates an in-service date for Unit No. 4 that is one quarter later, in March 2024. Meeting the projected in-service date for Unit No. 4 primarily depends on Unit No. 3 progress through fuel load, startup and testing, overall construction productivity and production levels significantly improving, particularly in electrical installation, including terminations, as well as appropriate levels of craft laborers, particularly electricians and pipefitters, being added and maintained. As Unit No. 3 completes system turnover from construction and moves to testing and transitions to operations, ongoing and potential future challenges include construction productivity and final component and pre-operational tests. As Unit No. 4 progresses through construction and transitions into testing, ongoing and potential future challenges include the pace and quality of electrical installation; availability of craft and supervisory resources; the pace of work package closures and system turnovers; and the timeframe and duration of hot functional and other testing. As construction, including subcontract work, continues on Unit No. 4, ongoing or future challenges include 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; and procurement and related installation. New challenges may arise, particularly as Units No. 3 and No. 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to 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). The ongoing and potential future challenges described above may 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. Additional license amendment requests may be filed with the Nuclear Regulatory Commission. 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. On March 25, 2022, the Nuclear Regulatory Commission completed its follow up inspection related to the November 2021 final significance report on its special inspection to review the root cause of this additional construction remediation work and the corresponding corrective action plans. The Nuclear Regulatory Commission closed the findings identified in November 2021 and returned Unit No. 3 to the Nuclear Regulatory Commission’s baseline inspection program. Various design and other licensing-based compliance matters, including the completion of inspections, tests, analyses, and acceptance criteria documentation for Unit No. 4 and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, have arisen and 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. The ultimate outcome of these matters cannot be determined at this time. Co-Owner Contracts and Other Information 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 report (VCM 19) 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 to mitigate 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 VCM 19 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 VCM 19 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 VCM 19 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 VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, has a one-time option 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 share of construction costs actually incurred in excess of the EAC in VCM 19 plus $2.1 billion. If any Co-owner elects to exercise this tender option, Georgia Power would have the option to cancel the project in lieu of accepting the offer to purchase a portion of the Co-owner’s ownership interest. If Georgia Power does not elect to cancel the project, then Georgia Power must accept the offer, and the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the percentage of the cumulative amount of construction costs paid by such tendering Co-owner as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of the tendering Co-owner in accordance with the second and third bullets above will be treated as payments made by that 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 proportionate reduction of our 30% ownership interest. The VCM 19 total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. As of December 31, 2021, budget increases since VCM 19 have reached $3.4 billion for all Co-owners. As a result of these increases, we believe that the tender option was triggered at the Co-owner construction budget vote on February 14, 2022 and that Georgia Power’s increased responsibility for certain construction costs as described above commenced in March 2022. On June 17, 2022, we notified Georgia Power of our election to exercise the tender option and cap our capital costs in exchange for a proportionate reduction of our 30% interest in the two new units. Our decremental ownership interest will be calculated and conveyed to Georgia Power after both Vogtle units are placed in service. Based on the current project budget, our schedule assumptions and our interpretation of the Global Amendments, our project budget is $8.1 billion and we expect to transfer approximately 50 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately 28%. By exercising the tender option and based on current assumptions, we estimate that we will avoid incurring approximately $475 million in construction costs associated with the project. However, if the total project budget exceeds the current budget, our ownership share and megawatts would be further reduced. On July 26, 2022, the City of Dalton notified Georgia Power that it had elected to exercise its tender option. MEAG must notify Georgia Power by August 27, 2022 whether it intends to exercise its tender option. Georgia Power and the other Co-owners do not agree on certain aspects of the tender option, including the dollar amount that triggers each Co-owner’s option to tender a portion of its ownership interest to Georgia Power under the tender option or the extent to which costs that are the result of a force majeure event (such as COVID-19) impact the point at which the tender option is triggered. For purposes of determining when the Co-owners’ option to tender has been triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. Georgia Power and the other Co-owners also do not agree on the dollar amount that triggers Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above is triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in the nineteenth VCM report by $800 million to $2.1 billion. Accordingly, in March 2022, we notified Georgia Power of a billing dispute with regards to both the starting dollar amount and the application of costs resulting from a force majeure event and how such amounts impact the thresholds and timing of the cost-sharing and tender option provisions. On June 18, 2022, after completing the dispute resolution procedures set forth in the Ownership Participation Agreement for the additional Vogtle units, we and MEAG filed separate lawsuits against Georgia Power in the Superior Court of Fulton County, Georgia seeking to enforce the terms of the Global Amendments. The lawsuits seek declaratory judgment that the cost sharing and tender provisions of the Global Amendments have been triggered based on a VCM 19 forecast of $17.1 billion . The lawsuits also allege breach of contract and assert other claims and seek damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with our and MEAG’s interpretations of the Global Amendments. Subsequently, the City of Dalton filed a motion to intervene and join in our and MEAG's claims. On July 28, 2022, Georgia Power filed a counterclaim against us seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power’s related financial obligations. Based on the current project budget and Georgia Power’s interpretation of the Global Amendments, our project budget would be $8.6 billion, an increase of approximately $475 million, and we would retain our 30% interest in the additional units. Pursuant to the Joint Ownership Agreements, as amended by the Global Amendments, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units No. 3 and No. 4, respectively (each, a Project Adverse Event). The schedule extensions, announced in February 2022, which reflected a cumulative delay of over a year for each unit from the schedules approved in the seventeenth VCM report, triggered the requirement for the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 to vote to continue construction, and the Co-owners unanimously voted to continue construction. The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note L of Notes to Unaudited Consolidated Financial Statements. The ultimate outcome of these matters cannot be determined at this time. See “Item 1A – RISK FACTORS” in our 2021 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units

Measurement of Credit Losses on

Measurement of Credit Losses on Financial Instruments	6 Months Ended
	Jun. 30, 2022
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 credit losses (Topic 326) 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.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2022
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events. In July 2022, the Georgia Public Service Commission approved Georgia Power’s 2022 integrated resource plan. This plan requested the decertification of coal-fired Plant Wansley, of which we own a 30% interest, by August 31, 2022. Following decertification, Georgia Power has stated it intends to retire Plant Wansley. In connection with this retirement, we created a regulatory asset to defer a portion of the accelerated depreciation expense and recover the deferred costs no later than December 31, 2040. The Georgia Public Service Commission also approved Georgia Power’s modified closure proposal for the ash pond at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Wansley, beneficial use of the coal ash, and managing construction and operational risks of the previous close in place design. The Georgia Environmental Protection Department must also approve the change in closure plans. We are continuing to evaluate the costs associated with the modified closure plan; however, preliminary estimates provided by Georgia Power indicate that the modified closure plan could increase our costs to close the ash pond by approximately $100 million (in 2021 dollars). Given the pending approvals and level of uncertainty associated with the cost and estimated timing of closure by removal, we have concluded that these costs are not reasonably estimable and are therefore not reflected in the coal ash related asset retirement obligations at June 30, 2022. We expect to receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures prior to year-end 2022. See Note J of Notes to Unaudited Consolidated Financial Statements for additional information regarding the retirement of Plant Wansley and the associated regulatory asset and see “Item 1 – OUR

Recently Issued or Adopted Ac_2

Recently Issued or Adopted Accounting Pronouncements (Policies)	6 Months Ended
	Jun. 30, 2022
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 have fully completed our evaluation of this new standard and we do not expect this standard will have a material impact on our consolidated financial statements.

Fair Value (Tables)

Fair Value (Tables)	6 Months Ended
	Jun. 30, 2022
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 June 30, 2022 and December 31, 2021. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs June 30, 2022 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 199,520 $ 199,520 $ — $ — International equity trust 109,140 — 109,140 — Corporate bonds and debt 86,470 — 86,470 — US Treasury securities 41,590 41,590 — — Mortgage backed securities 24,902 — 24,902 — Domestic mutual funds 54,219 54,219 — — Federal agency securities 3,138 — 3,138 — Non-US Gov't bonds & private placements 2,988 — 2,988 — Other 13,747 13,747 — — Long-term investments: International equity trust 32,940 — 32,940 — Corporate bonds and debt 19,749 — 19,749 — US Treasury securities 157 157 — — Mortgage backed securities 10,976 — 10,976 — Domestic mutual funds 264,867 264,867 — — Treasury STRIPS 308,949 — 308,949 — Non-US Gov't bonds & private placements 1,441 — 1,441 — Other 9,218 9,218 — — Short-term investments: Treasury STRIPS 42,691 — 42,691 — Natural gas swaps 184,859 — 184,859 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2021 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 249,999 $ 249,999 $ — $ — International equity trust 140,718 — 140,718 — Corporate bonds and debt 72,936 — 72,369 567 US Treasury securities 53,321 53,321 — — Mortgage backed securities 40,460 — 40,460 — Domestic mutual funds 75,384 75,384 — — Municipal bonds 1,133 — 1,133 — Federal agency securities 9,608 — 9,608 — Other 16,351 13,623 2,728 — Long-term investments: International equity trust 35,873 — 35,873 — Corporate bonds and debt 14,022 — 12,656 1,366 US Treasury securities 15,259 15,259 — — Mortgage backed securities 12,021 — 12,021 — Domestic mutual funds 277,937 277,937 — — Federal agency securities 257 — 257 — Treasury STRIPS 350,532 — 350,532 — Other 5,478 5,478 — — Natural gas swaps 63,994 — 63,994 —
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 June 30, 2022 and December 31, 2021 were as follows: 2022 2021 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 11,454,480 $ 10,704,745 $ 10,915,054 $ 12,741,046

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2022
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 as of June 30, 2022 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2022 14.7 2023 27.9 2024 25.7 2025 22.2 2026 16.9 2027 3.5 Total 110.9
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 June 30, 2022 and December 31, 2021. Balance Sheet Location Fair Value 2022 2021 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 60,849 $ 23,596 Natural gas swaps Other deferred charges $ 126,283 $ 40,398 Liabilities: Natural gas swaps Other current liabilities $ 2,273 $ — Natural gas swaps Other deferred credits $ — $ —
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 six months ended June 30, 2022 and 2021. Statement of Three Months Ended Six Months Ended June 30, 2022 2021 2022 2021 (dollars in thousands) Natural gas swaps gains Fuel $ 42,563 $ 2,297 $ 50,641 $ 2,398 Natural gas swaps losses Fuel (203) (67) (282) (1,311) Total $ 42,360 $ 2,230 $ 50,359 $ 1,087
Schedule of unrealized losses on derivative instruments deferred on the balance sheet	The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at June 30, 2022 and December 31, 2021. Balance Sheet Location 2022 2021 (dollars in thousands) Natural gas swaps Regulatory liability $ 184,859 $ 63,994 Total $ 184,859 $ 63,994

Investment Securities (Tables)

Investment Securities (Tables)	6 Months Ended
	Jun. 30, 2022
Investments, Debt and Equity Securities [Abstract]
Summary of debt and equity securities	The following tables summarize debt and equity securities as of June 30, 2022 and December 31, 2021. Gross Unrealized (dollars in thousands) June 30, 2022 Cost Gains Losses Fair Equity $ 312,999 $ 150,402 $ (6,975) $ 456,426 Debt 801,320 349 (32,819) 768,850 Other 1,426 — — 1,426 Total $ 1,115,745 $ 150,751 $ (39,794) $ 1,226,702 Gross Unrealized (dollars in thousands) December 31, 2021 Cost Gains Losses Fair Equity $ 304,305 $ 280,127 $ (4,682) $ 579,750 Debt 774,580 4,859 (7,001) 772,438 Other 19,102 — (1) 19,101 Total $ 1,097,987 $ 284,986 $ (11,684) $ 1,371,289

Revenue Recognition (Tables)

Revenue Recognition (Tables)	6 Months Ended
	Jun. 30, 2022
Revenue from Contract with Customer [Abstract]
Schedule of sales to members and sales to non-members	Sales to members for the three and six months ended June 30, 2022 and 2021 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2022 2021 2022 2021 Capacity revenues $ 241,841 $ 232,431 $ 485,132 $ 488,255 Energy revenues 236,941 125,490 411,099 245,938 Total $ 478,782 $ 357,921 $ 896,231 $ 734,193 Member energy requirements supplied 59 % 62 % 58 % 59 % Sales to non-members during the three and six months ended June 30, 2022 and 2021 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2022 2021 2022 2021 Energy revenues $ 54,346 $ 206 $ 57,339 $ 265

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2022
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 June 30, 2022 December 31, 2021 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (270,241) (267,606) Total finance lease assets $ 32,491 $ 35,126 Lease liabilities—Finance leases Obligations under finance leases $ 57,249 $ 61,335 Long-term debt and finance leases due within one year 7,958 7,541 Total finance lease liabilities $ 65,207 $ 68,876 Classification June 30, 2022 December 31, 2021 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service, net $ 1,876 $ 2,293 Total operating lease assets $ 1,876 $ 2,293 Lease liabilities—Operating leases Capitalization—Other $ 1,212 $ 1,550 Other current liabilities 758 838 Total operating lease liabilities $ 1,970 $ 2,388
Schedule of lease cost	Three months ended Six months ended Lease Cost Classification June 30, 2022 June 30, 2021 June 30, 2022 June 30, 2021 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,886 $ 1,517 $ 3,771 $ 3,033 Interest on lease liabilities Interest expense 1,852 2,044 3,704 4,088 Operating lease cost: Inventory (1) & production expense 222 269 444 539 Total leased cost $ 3,960 $ 3,830 $ 7,919 $ 7,660 (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	June 30, 2022 December 31, 2021 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 6.42 6.90 Operating leases 8.83 8.01 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.83 % 4.73 %
Schedule of cash paid for amounts included in the measurement of lease liabilities	Six months ended June 30, 2022 2021 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,806 $ 4,180 Operating cash flows from operating leases $ 444 $ 539 Financing cash flows from finance leases $ 3,669 $ 3,295 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 as of June 30, 2022 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2022 $ 7,475 $ 485 $ 7,960 2023 14,949 708 15,657 2024 14,949 234 15,183 2025 14,949 72 15,021 2026 14,949 72 15,021 Thereafter 25,634 940 26,574 Total lease payments $ 92,905 $ 2,511 $ 95,416 Less: imputed interest (27,698) (541) (28,239) Present value of lease liabilities $ 65,207 $ 1,970 $ 67,177
Schedule of lessor's income from leases	Lease income recognized during the three and six months ended June 30, 2022 and 2021 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 (dollars in thousands) Lease income $ 1,669 $ 1,606 $ 3,314 $ 3,203

Restricted Cash and Investmen_2

Restricted Cash and Investments (Tables)	6 Months Ended
	Jun. 30, 2022
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 June 30, 2022 June 30, 2021 (dollars in thousands) Cash and cash equivalents $ 476,792 $ 399,551 Bond purchase fund 30,975 245,605 Restricted cash included in restricted cash and short-term investments 84,600 — Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 592,367 $ 645,156

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2022
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets and liabilities	The following regulatory assets and liabilities are reflected on the consolidated balance sheets as of June 30, 2022 and December 31, 2021. 2022 2021 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 31,199 $ 33,200 Amortization of financing leases(b) 33,043 34,179 Outage costs(c) 38,323 31,956 Asset retirement obligations—Ashpond and other(l) 343,197 335,231 Asset retirement obligations—Nuclear(l) 13,105 — Depreciation expense - Plant Vogtle(d) 36,261 36,973 Depreciation expense - Plant Wansley(e) 316,034 204,891 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,442 55,857 Interest rate options cost(g) 134,018 131,556 Deferral of effects on net margin—Smith Energy Facility(h) 139,702 142,675 Other regulatory assets(o) 7,717 2,272 Total Regulatory Assets $ 1,148,041 $ 1,008,790 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 22,871 $ 22,197 Deferral of effects on net margin—Hawk Road Energy Facility(h) 16,945 17,253 Deferral of effects on net margin—Effingham Energy Facility(p) 4,387 — Major maintenance reserve(j) 90,410 73,059 Amortization of financing leases(b) 7,007 8,457 Deferred debt service adder(k) 146,716 138,897 Asset retirement obligations—Nuclear(l) — 164,256 Revenue deferral plan(m) 354,673 359,799 Natural gas hedges(n) 184,859 63,994 Other regulatory liabilities(o) 1,382 1,537 Total Regulatory Liabilities $ 829,250 $ 849,449 Net Regulatory Assets $ 318,791 $ 159,341 (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 by the end of August 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, per each members' election, over the subsequent five-year period. (n) Represents the deferral of unrealized gains on natural gas hedges. (o) The amortization periods for other regulatory assets range up to 28 years and the amortization periods of other regulatory liabilities range up to 5 years. (p) Effects on net margin for the Effingham Energy Facility that are being deferred until on or before January 2026 and will be amortized over the remaining life of the plant.

Vogtle Units No. 3 and No. 4 _2

Vogtle Units No. 3 and No. 4 Construction Project (Tables)	6 Months Ended
	Jun. 30, 2022
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 June 30, 2022 for our share of the project. (in millions) Project Budget (Tender) Actual Costs at Construction Costs (1) $ 6,021 $ 5,842 Financing Costs 1,966 1,626 Subtotal $ 7,987 $ 7,468 Deferred Training Costs 54 46 Total Project Costs Before Contingency $ 8,041 $ 7,514 Oglethorpe-Level Contingency 59 — Total Contingency $ 59 $ — Totals $ 8,100 $ 7,514 (1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements.

General (Details)

General (Details)	6 Months Ended
	Jun. 30, 2022 member
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 ($)	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Fair value
Nuclear decommissioning trust fund	$ 535,714,000	$ 659,910,000
Long-term investments	648,297,000	711,379,000
Short-term investments	42,691,000	0
International equity trust
Fair value
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Natural gas swaps
Fair value
Derivative liabilities	$ 184,859,000	63,994,000
Recurring basis | Domestic equity
Fair value
Nuclear decommissioning trust fund	199,520,000	249,999,000
Recurring basis | International equity trust
Fair value
Nuclear decommissioning trust fund	109,140,000	140,718,000
Long-term investments	32,940,000	35,873,000
Recurring basis | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	86,470,000	72,936,000
Long-term investments	19,749,000	14,022,000
Recurring basis | US Treasury securities
Fair value
Nuclear decommissioning trust fund	41,590,000	53,321,000
Long-term investments	157,000	15,259,000
Recurring basis | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	24,902,000	40,460,000
Long-term investments	10,976,000	12,021,000
Recurring basis | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	54,219,000	75,384,000
Long-term investments	264,867,000	277,937,000
Recurring basis | Municipal bonds
Fair value
Nuclear decommissioning trust fund		1,133,000
Recurring basis | Federal agency securities
Fair value
Nuclear decommissioning trust fund	3,138,000	9,608,000
Long-term investments		257,000
Recurring basis | Treasury STRIPS
Fair value
Long-term investments	308,949,000	350,532,000
Short-term investments	42,691,000
Recurring basis | Other
Fair value
Nuclear decommissioning trust fund	13,747,000	16,351,000
Long-term investments	9,218,000	5,478,000
Recurring basis | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,988,000
Long-term investments	1,441,000
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	199,520,000	249,999,000
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	41,590,000	53,321,000
Long-term investments	157,000	15,259,000
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	54,219,000	75,384,000
Long-term investments	264,867,000	277,937,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Fair value
Nuclear decommissioning trust fund		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
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Treasury STRIPS
Fair value
Long-term investments	0	0
Short-term investments	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value
Nuclear decommissioning trust fund	13,747,000	13,623,000
Long-term investments	9,218,000	5,478,000
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
Long-term investments	0
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value
Derivative liabilities	184,859,000	63,994,000
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	109,140,000	140,718,000
Long-term investments	32,940,000	35,873,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	86,470,000	72,369,000
Long-term investments	19,749,000	12,656,000
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	24,902,000	40,460,000
Long-term investments	10,976,000	12,021,000
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		1,133,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	3,138,000	9,608,000
Long-term investments		257,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS
Fair value
Long-term investments	308,949,000	350,532,000
Short-term investments	42,691,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Other
Fair value
Nuclear decommissioning trust fund	0	2,728,000
Long-term investments	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,988,000
Long-term investments	1,441,000
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	0	567,000
Long-term investments	0	1,366,000
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
Recurring basis | Significant Unobservable Inputs (Level 3) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments		0
Recurring basis | Significant Unobservable Inputs (Level 3) | Treasury STRIPS
Fair value
Long-term investments	0	0
Short-term investments	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Other
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
Long-term investments	$ 0

Fair Value - Estimated fair val

Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Carrying Value
Fair Value
Long-term debt	$ 11,454,480	$ 10,915,054
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value
Long-term debt	$ 10,704,745	$ 12,741,046

Derivative Instruments - Gas he

Derivative Instruments - Gas hedges (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) MMBTU	Dec. 31, 2021 USD ($)
Derivative Instruments
Derivative asset | $	$ 184,859	$ 63,994
Notional volume of natural gas derivatives (in MMBTUs)	110.9
Three counterparties
Derivative Instruments
Credit collateral posted | $	$ 84,600
One counterparty
Derivative Instruments
Credit collateral posted | $		$ 1,800
2022
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	14.7
2023
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	27.9
2024
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	25.7
2025
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	22.2
2026
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	16.9
2027
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	3.5

Derivative Instruments - Fair v

Derivative Instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Assets:
Fair value of assets	$ 184,859	$ 63,994
Other current assets
Assets:
Fair value of assets	60,849	23,596
Other deferred charges
Assets:
Fair value of assets	126,283	40,398
Other current liabilities
Liabilities:
Fair value of liabilities	2,273	0
Other deferred credits
Liabilities:
Fair value of liabilities	$ 0	$ 0

Derivative Instruments - Realiz

Derivative Instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Gains and (losses) on derivative instruments
Net unrealized gains on derivative instruments			$ 184,859		$ 63,994
Natural gas swaps | Regulatory liability
Gains and (losses) on derivative instruments
Net unrealized gains on derivative instruments			184,859		$ 63,994
Natural gas swaps | Fuel
Gains and (losses) on derivative instruments
Gains	$ 42,563	$ 2,297	50,641	$ 2,398
Losses	(203)	(67)	(282)	(1,311)
Total	$ 42,360	$ 2,230	$ 50,359	$ 1,087

Investment Securities (Details)

Investment Securities (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Cost
Equity	$ 312,999	$ 304,305
Debt	801,320	774,580
Other	1,426	19,102
Total	1,115,745	1,097,987
Gains
Equity	150,402	280,127
Debt	349	4,859
Other	0	0
Total	150,751	284,986
Losses
Equity	(6,975)	(4,682)
Debt	(32,819)	(7,001)
Other	0	(1)
Total	(39,794)	(11,684)
Fair Value
Equity	456,426	579,750
Debt	768,850	772,438
Other	1,426	19,101
Total	$ 1,226,702	$ 1,371,289

Revenue Recognition (Details)

Revenue Recognition (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($) service member	Jun. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
Revenue Recognition
Number of electric distribution cooperative members | member			38
Number of services provided | service			2
Member energy requirements supplied	59%	62%	58%	59%
Margins for interest ratio			1.10
Targeted margins for interest ratio			1.14
Refund liability	$ 5,000,000	$ 4,500,000	$ 5,000,000	$ 4,500,000
Operating revenues	533,128,000	358,127,000	953,570,000	734,458,000
Members
Revenue Recognition
Operating revenues	478,782,000	357,921,000	896,231,000	734,193,000
Receivables from contracts	218,953,000		218,953,000		$ 143,715,000
Non-Members
Revenue Recognition
Operating revenues	54,346,000	206,000	57,339,000	265,000
Receivables from contracts	21,235,000		21,235,000		$ 302,000
Capacity revenues | Members
Revenue Recognition
Operating revenues	241,841,000	232,431,000	485,132,000	488,255,000
Energy revenues | Members
Revenue Recognition
Operating revenues	236,941,000	125,490,000	411,099,000	245,938,000
Energy revenues | Non-Members
Revenue Recognition
Operating revenues	$ 54,346,000	$ 206,000	$ 57,339,000	$ 265,000

Revenue Recognition - Managemen

Revenue Recognition - Management Program (Details) - USD ($) $ in Thousands	6 Months Ended		12 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2018
Vogtle Units No. 3 & No. 4
Operating revenues
Amounts billed under rate management program	$ 9,440	$ 7,729
Cumulative recovery of financing costs	121,076
Vogtle New Units
Operating revenues
Cumulative recovery of financing costs	363,215
Rate management program, additional collection period			5 years
Rate management program, billing period			5 years
Amounts billed under additional rate management program	$ 5,887	$ 80,087

Leases - Summary (Details)

Leases - Summary (Details)	6 Months Ended
	Jun. 30, 2022 option lease
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%
Number of finance leases	4

Leases - Balance Sheet Impact (

Leases - Balance Sheet Impact (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021
Right-of-Use Assets—Finance leases
Right-of-use assets	$ 302,732	$ 302,732
Less: Accumulated provision for depreciation	(270,241)	(267,606)
Total finance lease assets	32,491	35,126
Lease liabilities—Finance leases
Obligations under finance leases	57,249	61,335
Long-term debt and finance leases due within one year	7,958	7,541
Total finance lease liabilities	$ 65,207	$ 68,876
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, net	$ 1,876	$ 2,293
Total operating lease assets	$ 1,876	$ 2,293
Right of Use Assets, Operating, Statement of Financial Position	In service	In service
Lease liabilities—Operating leases
Capitalization—Other	$ 1,212	$ 1,550
Other current liabilities	758	838
Total operating lease liabilities	$ 1,970	$ 2,388
Operating Lease, Liability, Noncurrent, Statement of Financial Position	Obligation under Hydro Facility Transactions	Obligation under Hydro Facility Transactions
Operating Lease, Liability, Current, Statement of Financial Position	Other current liabilities	Other current liabilities

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Lease Cost
Amortization of leased assets	$ 1,886	$ 1,517	$ 3,771	$ 3,033
Interest on lease liabilities	1,852	2,044	3,704	4,088
Operating lease cost:	222	269	444	539
Total leased cost	$ 3,960	$ 3,830	$ 7,919	$ 7,660
Weighted-average remaining lease term (in years)
Finance leases	6 years 5 months 1 day		6 years 5 months 1 day		6 years 10 months 24 days
Operating leases	8 years 9 months 29 days		8 years 9 months 29 days		8 years 3 days
Weighted-average discount rate:
Finance leases	11.05%		11.05%		11.05%
Operating leases	4.83%		4.83%		4.73%

Leases - Other Lease Disclosure

Leases - Other Lease Disclosures (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Lessee
Operating cash flows from finance leases			$ 3,806	$ 4,180
Operating cash flows from operating leases			444	539
Financing cash flows from finance leases			3,669	3,295
Right-of-use assets obtained in exchange for new operating lease liabilities			0	0
Finance Leases
2022	$ 7,475		7,475
2023	14,949		14,949
2024	14,949		14,949
2025	14,949		14,949
2026	14,949		14,949
Thereafter	25,634		25,634
Total lease payments	92,905		92,905
Less: imputed interest	(27,698)		(27,698)
Total finance lease liabilities	65,207		65,207		$ 68,876
Operating Leases
2022	485		485
2023	708		708
2024	234		234
2025	72		72
2026	72		72
Thereafter	940		940
Total lease payments	2,511		2,511
Less: imputed interest	(541)		(541)
Total operating lease liabilities	1,970		1,970		$ 2,388
Total
2022	7,960		7,960
2023	15,657		15,657
2024	15,183		15,183
2025	15,021		15,021
2026	15,021		15,021
Thereafter	26,574		26,574
Total lease payments	95,416		95,416
Less: imputed interest	(28,239)		(28,239)
Present value of lease liabilities	67,177		67,177
Lessor
Lease income	$ 1,669	$ 1,606	$ 3,314	$ 3,203

Contingencies and Regulatory _2

Contingencies and Regulatory Matters (Details)	6 Months Ended
	Jun. 30, 2022 plaintiff
Contingencies and Regulatory Matters
Number of plaintiffs	70

Restricted Cash and Investmen_3

Restricted Cash and Investments - Narrative (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021	Oct. 01, 2021	Sep. 30, 2021
Restricted Investments Note [Abstract]
Guaranteed interest rate on deposit (as a percent)			0.09%	4%
Restricted investments	$ 135,195	$ 320,052
Restricted cash and short-term investments	$ 135,195	$ 246,350

Restricted Cash and Investmen_4

Restricted Cash and Investments - Reconciliation of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Thousands	Jun. 30, 2022	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Restricted Investments Note [Abstract]
Cash and cash equivalents	$ 476,792	$ 579,350	$ 399,551
Bond purchase fund	30,975	0	245,605
Restricted cash included in restricted cash and short-term investments	84,600		0
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$ 592,367	$ 581,150	$ 645,156	$ 405,511

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2022	Dec. 31, 2021
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 1,148,041	$ 1,008,790
Total Regulatory Liabilities	829,250	849,449
Net Regulatory Assets	318,791	159,341
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	22,871	22,197
Deferral of effects on net margin - Hawk Road Energy Facility | Hawk Road Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	16,945	17,253
Deferral of effects on net margin - Hawk Road Energy Facility | Effingham Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	4,387	0
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	90,410	73,059
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	7,007	8,457
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	146,716	138,897
Asset retirement obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	0	164,256
Revenue deferral plan
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 354,673	359,799
Amortization Period	5 years
Natural gas hedges
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 184,859	63,994
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 1,382	1,537
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization Period	5 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 31,199	33,200
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	$ 33,043	34,179
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 38,323	31,956
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	$ 343,197	335,231
Asset retirement obligations | Nuclear
Regulatory Assets and Liabilities
Total Regulatory Assets	13,105	0
Depreciation expense | Plant Vogtle
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 36,261	36,973
Operating license expected extension period for Plant Vogtle	20 years
Operating license period	40 years
Depreciation expense | Plant Wansley
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 316,034	204,891
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	55,442	55,857
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	134,018	131,556
Deferral of effects on net margin - Smith Energy Facility | Smith Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Assets	139,702	142,675
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 7,717	$ 2,272
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	28 years

Debt - Department of Energy Loa

Debt - Department of Energy Loan Guarantee (Details)	6 Months Ended
	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Mar. 22, 2019 USD ($)	Dec. 31, 2017 USD ($)	Feb. 20, 2014 USD ($) note
Debt
Repayments of long-term debt	$ 256,747,000	$ 123,520,000
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%
Long-term debt | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 4,275,348,382
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 (as a percent)			70%
Repayments of long-term debt	243,505,000
Long-term debt | FFB | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 1,262,000,000
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	6 Months Ended
	Jul. 31, 2022	Jun. 30, 2022
Debt
Advances received on loans		$ 52,503
Subsequent Event
Debt
Advances received on loans	$ 10,528

Debt - First Mortgage Bonds (De

Debt - First Mortgage Bonds (Details) $ in Thousands	Apr. 12, 2022 USD ($)
Debt
Repayments of commercial paper	$ 493,405
Mortgage Bonds | Series 2022A First Mortgage Bonds
Debt
Debt instrument, face amount	$ 500,000
Interest rate	4.50%

Debt - Pollution Control Revenu

Debt - Pollution Control Revenue Bonds (Details) - USD ($) $ in Thousands	3 Months Ended
	Sep. 30, 2022	Jun. 30, 2022	Dec. 31, 2021	Jun. 30, 2021	Dec. 31, 2020
Debt
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows		$ 592,367	$ 581,150	$ 645,156	$ 405,511
Cash and cash equivalents		476,792	579,350	399,551
Restricted cash included in restricted cash and short-term investments		84,600		0
Bond purchase fund		$ 30,975	$ 0	$ 245,605
Municipal bonds | Series 2017 Pollution Control Revenue Bonds | Forecast
Debt
Debt redemption amount	$ 31,000

Vogtle Units No. 3 and No. 4 _3

Vogtle Units No. 3 and No. 4 Construction Project - Narrative (Details) $ in Millions		6 Months Ended
	Feb. 18, 2019 USD ($)	Jun. 30, 2022 USD ($) unit MW	Dec. 31, 2021 USD ($)
Vogtle Units No. 3 & No. 4
Public Utility Property Plant and Equipment
Total investment in additional Vogtle units		$ 7,500
Ownership interest (as a percent)		30%
Monthly delay cost, exercise of tender option		$ 30
Remaining share paid by counterparty upon exercise of tender option (as a percent)		100%
Budget increases since the nineteenth VCM			$ 3,400
Percentage of disallowed costs excluded from adverse event triggers		6%
Vogtle Units No. 3 & No. 4 | Jointly Owned Nuclear Power Plant
Public Utility Property Plant and Equipment
Release of generating capacity with exercise of tender option (in megawatts) | MW		50
Proportionate ownership share with exercise of tender option (as a percent)		28%
Total project cost		$ 8,100
Vogtle Units No. 3 & No. 4 | Financial Exposure Term One
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30%
Vogtle Units No. 3 & No. 4 | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30%
Vogtle Units No. 3 & No. 4 | Minimum
Public Utility Property Plant and Equipment
COVID related costs		$ 350
Vogtle Units No. 3 & No. 4 | Maximum
Public Utility Property Plant and Equipment
COVID related costs		438
Vogtle Units No. 3 & No. 4 | Ownership participation agreement
Public Utility Property Plant and Equipment
Project budget		8,100
Project budget had tender option not been exercised		$ 8,600
Ownership share, generating capacity (in megawatts) | MW		660
Construction cost savings due to exercise of tender option		$ 475
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
Additional construction costs	$ 800
Total project cost		$ 17,100
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Jointly Owned Nuclear Power Plant
Public Utility Property Plant and Equipment
Total project cost		17,100
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Jointly Owned Nuclear Power Plant | Georgia Power
Public Utility Property Plant and Equipment
Project budget		8,600
Total project cost		18,380
Increase in project budget based on Georgia Power's interpretation		$ 475
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 (as a percent)	55.70%
Additional construction costs, responsibility of co-owner	$ 80
Proportionate share of additional construction costs	$ 44
Proportionate share of construction costs, remaining co-owners (as a percent)	44.30%
Proportionate share of construction costs (as a percent)	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 (as a percent)	65.70%
Additional construction costs, responsibility of co-owner	$ 100
Proportionate share of additional construction costs	$ 55
Proportionate share of construction costs, remaining co-owners (as a percent)	34.30%
Proportionate share of construction costs (as a percent)	19%
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term Three
Public Utility Property Plant and Equipment
Additional construction costs triggering option to tender ownership	$ 2,100
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum
Public Utility Property Plant and Equipment
Ownership approval to change primary construction contractor (as a percent)		90%
Ownership approval required to continue construction (as a percent)		90%
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term One
Public Utility Property Plant and Equipment
Additional construction costs	800
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Additional construction costs	1,600
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term Three
Public Utility Property Plant and Equipment
Additional construction costs triggering option to tender ownership	800
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term One
Public Utility Property Plant and Equipment
Additional construction costs	1,600
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Additional construction costs	2,100
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term Three
Public Utility Property Plant and Equipment
Additional construction costs triggering option to tender ownership	$ 2,100
Vogtle Unit Number 4
Public Utility Property Plant and Equipment
Monthly delay cost, exercise of tender option		$ 13

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 $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($)
Actual Costs at June 30, 2022
Proceeds from guarantee agreement	$ 1,100
Cost sharing benefits	99
Jointly Owned Nuclear Power Plant
Project Budget (Tender)
Construction Costs	6,021
Financing Costs	1,966
Subtotal	7,987
Deferred Training Costs	54
Total Project Costs Before Contingency	8,041
Oglethorpe-Level Contingency	59
Total Contingency	59
Totals	8,100
Actual Costs at June 30, 2022
Construction Costs	5,842
Financing Costs	1,626
Subtotal	7,468
Deferred Training Costs	46
Total Project Costs Before Contingency	7,514
Oglethorpe-Level Contingency	0
Total Contingency	0
Totals	$ 7,514

Subsequent Events (Details)

Subsequent Events (Details) - Plant Wansley - Subsequent Event $ in Millions	1 Months Ended
	Jul. 31, 2022 USD ($)
Subsequent Event [Line Items]
Ownership interest (as a percent)	30%
Cost to close plant	$ 100