Oglethorpe Power 10-Q 11 May 23 2023 Q1 Quarterly report Financial data

Cover Page

Cover Page	3 Months Ended
	Mar. 31, 2023 shares
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2023
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	2023
Document Fiscal Period Focus	Q1

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Electric plant:
In service	$ 9,389,367	$ 9,266,627
Right-of-use assets—finance leases	302,732	302,732
Less: Accumulated provision for depreciation	(5,230,497)	(5,183,589)
Electric plant in service, net	4,461,602	4,385,770
Nuclear fuel, at amortized cost	392,621	388,303
Construction work in progress	7,885,910	7,716,035
Total electric plant	12,740,133	12,490,108
Investments and funds:
Nuclear decommissioning trust fund	574,121	540,716
Investment in associated companies	77,750	78,937
Long-term investments	666,010	669,479
Other	33,032	32,561
Total investments and funds	1,350,913	1,321,693
Current assets:
Cash and cash equivalents	390,821	595,381
Restricted cash and short-term investments	16,000	104,431
Short-term investments	76,064	61,702
Receivables	163,909	220,015
Inventories, at average cost	315,715	297,951
Prepayments and other current assets	16,064	51,409
Total current assets	978,573	1,330,889
Deferred charges and other assets:
Regulatory assets	1,214,977	1,212,305
Prepayments to Georgia Power Company	13,441	20,873
Other	81,153	113,502
Total deferred charges	1,309,571	1,346,680
Total assets	16,379,190	16,489,370
Capitalization:
Patronage capital and membership fees	1,216,537	1,192,127
Long-term debt	11,392,980	11,512,513
Obligation under finance leases	52,937	52,937
Obligation under Rocky Mountain transactions	28,416	27,945
Other	1,961	2,256
Total capitalization	12,692,831	12,787,778
Current liabilities:
Long-term debt and finance leases due within one year	320,331	322,102
Short-term borrowings	813,025	655,650
Accounts payable	82,251	203,705
Accrued interest	92,343	105,452
Member power bill prepayments, current	49,154	54,443
Other current liabilities	92,073	153,941
Total current liabilities	1,449,177	1,495,293
Deferred credits and other liabilities:
Asset retirement obligations	1,444,558	1,343,743
Member power bill prepayments, non-current	58,177	53,877
Regulatory liabilities	718,276	792,190
Other	16,171	16,489
Total deferred credits and other liabilities	2,237,182	2,206,299
Total equity and liabilities	$ 16,379,190	$ 16,489,370

Consolidated Statements of Reve

Consolidated Statements of Revenues and Expenses (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Operating revenues:
Total operating revenues	$ 389,453	$ 420,442
Operating expenses:
Fuel	133,168	165,484
Production	93,467	95,780
Depreciation and amortization	72,674	70,926
Purchased power	17,630	16,875
Accretion	15,508	13,532
Total operating expenses	332,447	362,597
Operating margin	57,006	57,845
Other income:
Investment income	16,382	11,847
Other	2,925	3,030
Total other income	19,307	14,877
Interest charges:
Interest expense	123,707	104,669
Allowance for debt funds used during construction	(74,430)	(56,773)
Amortization of debt discount and expense	2,626	2,846
Net interest charges	51,903	50,742
Net margin	24,410	21,980
Members
Operating revenues:
Total operating revenues	387,653	417,449
Non-Members
Operating revenues:
Total operating revenues	$ 1,800	$ 2,993

Consolidated Statements of Patr

Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Increase (Decrease) in Members' Capital
Net margin	$ 24,410	$ 21,980
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Beginning balance	1,192,127	1,130,423
Net margin	24,410	21,980
Ending balance	$ 1,216,537	$ 1,152,403

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash flows from operating activities:
Net margin	$ 24,410	$ 21,980
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	66,365	92,211
Accretion cost	15,508	13,532
Amortization of deferred gains	(447)	(447)
Allowance for equity funds used during construction	(149)	(135)
Deferred outage costs	(21,198)	(22,228)
Loss on sale of investments	1,289	8,271
Regulatory deferral of costs associated with nuclear decommissioning	(8,519)	(14,694)
Other	(863)	974
Change in operating assets and liabilities:
Receivables	49,887	(8,620)
Inventories	(17,711)	(715)
Prepayments and other current assets	4,027	5,954
Accounts payable	(116,354)	(78,836)
Accrued interest	(13,109)	(18,662)
Accrued taxes	(36,722)	16,180
Other current liabilities	(26,841)	29,836
Member power bill prepayments	(989)	(7,988)
Rate management program collections, net	(9,494)	11,017
Total adjustments	(115,320)	25,650
Net cash (used in) provided by operating activities	(90,910)	47,630
Cash flows from investing activities:
Property additions	(259,123)	(280,364)
Activity in nuclear decommissioning trust fund—Purchases	(2,500)	(195,038)
Activity in nuclear decommissioning trust fund - Proceeds	283	192,858
Decrease in restricted investments	74,031	123,232
Activity in other long-term investments—Purchases	(63,505)	(111,490)
Activity in other long-term investments - Proceeds	68,226	94,279
Other	8,153	(3,718)
Net cash used in investing activities	(174,435)	(180,241)
Cash flows from financing activities:
Long-term debt proceeds	15,431	102,185
Long-term debt payments	(137,732)	(115,168)
Increase in short-term borrowings, net	157,375	60,501
Other	11,311	10,496
Net cash provided by financing activities	46,385	58,014
Net decrease in cash, cash equivalents and restricted cash	(218,960)	(74,597)
Cash, cash equivalents and restricted cash at beginning of period	625,781	581,150
Cash, cash equivalents and restricted cash at end of period	406,821	506,553
Cash paid for—
Interest (net of amounts capitalized)	61,915	66,117
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	87,509	0
Accrued property additions at end of period	$ 69,557	$ 21,469

General

General	3 Months Ended
	Mar. 31, 2023
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 periods ended March 31, 2023 and 2022. 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) depreciation rates, such as determining the depreciable service lives and net salvage value. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading.

Fair Value

Fair Value	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 and December 31, 2022. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs March 31, 2023 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 219,406 $ 219,406 $ — $ — International equity trust 120,518 — 120,518 — Corporate bonds and debt 64,323 — 64,294 29 US Treasury securities 50,233 50,233 — — Mortgage backed securities 42,029 — 42,029 — Domestic mutual funds 60,724 60,724 — — Federal agency securities 4,243 — 4,243 — International mutual funds 698 — 698 — Non-US Gov't bonds & private placements 2,760 — 2,760 — Other 9,187 9,187 — — Long-term investments: International equity trust 37,645 — 37,645 — Corporate bonds and debt 20,467 — 20,467 — US Treasury securities 16,322 16,322 — — Mortgage backed securities 2,445 — 2,445 — Domestic mutual funds 315,433 315,433 — — Treasury STRIPS 271,338 — 271,338 — Non-US Gov't bonds & private placements 1,960 — 1,960 — Other 400 400 — — Short-term investments: Treasury STRIPS 76,064 — 76,064 — Natural gas swaps 64,584 — 64,584 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2022 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 204,129 $ 204,129 $ — $ — International equity trust 111,266 — 111,266 — Corporate bonds and debt 60,806 — 60,788 18 US Treasury securities 49,775 49,775 — — Mortgage backed securities 41,210 — 41,210 — Domestic mutual funds 57,348 57,348 — — Federal agency securities 2,037 — 2,037 — Non-US Gov't bonds & private placements 2,890 — 2,890 — International mutual funds 653 — 653 — Other 10,602 10,602 — — Long-term investments: International equity trust 33,606 — 33,606 — Corporate bonds and debt 10,473 — 10,473 — US Treasury securities 15,488 15,488 — — Mortgage backed securities 12,113 — 12,113 — Domestic mutual funds 302,302 302,302 — — Treasury STRIPS 293,281 — 293,281 — Non-US Gov't bonds & private placements 1,976 — 1,976 — Other 240 240 — — Short-term investments: Treasury STRIPS 61,702 — 61,702 — Natural gas swaps 131,804 — 131,804 — 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 March 31, 2023 and December 31, 2022 were as follows: 2023 2022 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 11,818,058 $ 10,618,552 $ 11,940,359 $ 10,194,954 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 March 31, 2023 and December 31, 2022 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	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023, 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 March 31, 2023 and December 31, 2022, the estimated fair values of our natural gas contracts were net assets of approximately $64,584,000 and $131,804,000, respectively. At March 31, 2023 and December 31, 2022, one of our counterparties was required to post credit collateral totaling $16,000,000 and $30,400,000 , respectively, 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 item within our unaudited consolidated balance sheets. The following table reflects the notional volume of our natural gas derivatives as of March 31, 2023 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2023 30.3 2024 30.4 2025 24.9 2026 19.9 2027 7.6 Total 113.1 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at March 31, 2023 and December 31, 2022. Balance Sheet Location Fair Value 2023 2022 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 3,966 $ 35,285 Natural gas swaps Other deferred charges $ 68,232 $ 99,725 Liabilities: Natural gas swaps Other current liabilities $ 7,614 $ 3,206 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 months ended March 31, 2023 and 2022. Statement of Three Months Ended 2023 2022 (dollars in thousands) Natural gas swaps gains Fuel $ 135 $ 8,078 Natural gas swaps losses Fuel (9,397) (79) Total $ (9,262) $ 7,999 The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at March 31, 2023 and December 31, 2022. Balance Sheet Location 2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 64,584 $ 131,804 Total $ 64,584 $ 131,804

Investments Securities

Investments Securities	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 and December 31, 2022. Gross Unrealized (dollars in thousands) March 31, 2023 Cost Gains Losses Fair Equity $ 324,488 $ 191,858 $ (7,030) $ 509,316 Debt 830,095 1,698 (34,803) 796,990 Other 9,885 30 (26) 9,889 Total $ 1,164,468 $ 193,586 $ (41,859) $ 1,316,195 Gross Unrealized (dollars in thousands) December 31, 2022 Cost Gains Losses Fair Equity $ 323,907 $ 159,445 $ (8,949) $ 474,403 Debt 833,035 372 (46,369) 787,038 Other 10,445 20 (9) 10,456 Total $ 1,167,387 $ 159,837 $ (55,327) $ 1,271,897

Recently Issued or Adopted Acco

Recently Issued or Adopted Accounting Pronouncements	3 Months Ended
	Mar. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently Issued or Adopted Accounting Pronouncements	Recently Issued or Adopted Accounting Pronouncements. As of March 31, 2023, we have implemented all applicable new accounting standards and updates issued by the Financial Accounting Standards Board (FASB) that were in effect. There were no applicable standards or updates during the three months ended March 31, 2023 that had a material impact on our consolidated financial statements.

Revenue Recognition

Revenue Recognition	3 Months Ended
	Mar. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue Recognition	Revenue Recognition. As an electric membership cooperative, our principal business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated to pay us for capacity and energy we furnish under the wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. As of March 31, 2023 and December 31, 2022, 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 are billed and recognized in accordance with the terms of the associated 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 three-month periods ended March 31, 2023 and 2022, we provided approximately 64% and 57% of our members' energy requirements, respectively. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2023, 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 March 31, 2023, we did not recognize a refund liability. As of December 31, 2022, we recognized refund liabilities totaling $28,471,000. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members for the three months ended March 31, 2023 and 2022 were as follows: Three Months Ended (dollars in thousands) 2023 2022 Capacity revenues $ 242,043 $ 243,291 Energy revenues 145,610 174,158 Total $ 387,653 $ 417,449 Member energy requirements supplied 64 % 57 % Receivables from contracts with our members at March 31, 2023 and December 31, 2022 were $126,448,000 and $187,401,000, respectively. Sales to non-members during the three months ended March 31, 2023 and 2022 were as follows: Three Months Ended (dollars in thousands) 2023 2022 Energy revenues $ 1,037 $ 2,993 Capacity revenues 763 — Total $ 1,800 $ 2,993 Receivables from the sale of electricity to non-members were $820,000 at March 31, 2023 and $8,787,000 at December 31, 2022 and are primarily from the sale of the Effingham deferring members’ output. The remainder of our receivables is primarily related to transactions with affiliated companies and investment income which were $35,867,000 and $13,834,000 at March 31, 2023 and December 31, 2022, respectively. Energy revenues from non-members for the three months ended March 31, 2023 were primarily from the sale of the Effingham deferring members' output into the wholesale market. For the three months ended March 31, 2023, we recognized capacity revenues from non-members related to our Washington County acquisition in December 2022. For additional information regarding the Washington County acquisition, see Note 14 in our 2022 Form 10-K. 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 three months ended March 31, 2023 and 2022 were $1,761,000 and $3,861,000, respectively. The cumulative amount billed since inception of the program totaled $128,193,000.

Leases

Leases	3 Months Ended
	Mar. 31, 2023
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 months ended March 31, 2023 and 2022 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 October 31, 2026. 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 March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (274,194) (272,876) Total finance lease assets $ 28,538 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 52,937 $ 52,937 Long-term debt and finance leases due within one year 8,398 8,398 Total finance lease liabilities $ 61,335 $ 61,335 Classification March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 3,032 $ 3,326 Total operating lease assets $ 3,032 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,961 $ 2,256 Other current liabilities 1,084 1,164 Total operating lease liabilities $ 3,045 $ 3,420 Three months ended Lease Cost Classification March 31, 2023 March 31, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,099 $ 1,885 Interest on lease liabilities Interest expense 1,638 1,852 Operating lease cost: Inventory (1) & production expense 329 222 Total leased cost $ 4,066 $ 3,959 (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. March 31, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.69 5.94 Operating leases 6.76 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % Three months ended March 31, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 409 $ 303 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of March 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 14,949 $ 914 $ 15,863 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,683 868 11,551 Total lease payments $ 85,428 $ 3,695 $ 89,123 Less: imputed interest (24,093) (650) (24,743) Present value of lease liabilities $ 61,335 $ 3,045 $ 64,380 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 months ended March 31, 2023 and 2022 was as follows: Three Months Ended March 31, 2023 2022 (dollars in thousands) Lease income $ 1,685 $ 1,645
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 months ended March 31, 2023 and 2022 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 October 31, 2026. 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 March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (274,194) (272,876) Total finance lease assets $ 28,538 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 52,937 $ 52,937 Long-term debt and finance leases due within one year 8,398 8,398 Total finance lease liabilities $ 61,335 $ 61,335 Classification March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 3,032 $ 3,326 Total operating lease assets $ 3,032 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,961 $ 2,256 Other current liabilities 1,084 1,164 Total operating lease liabilities $ 3,045 $ 3,420 Three months ended Lease Cost Classification March 31, 2023 March 31, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,099 $ 1,885 Interest on lease liabilities Interest expense 1,638 1,852 Operating lease cost: Inventory (1) & production expense 329 222 Total leased cost $ 4,066 $ 3,959 (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. March 31, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.69 5.94 Operating leases 6.76 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % Three months ended March 31, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 409 $ 303 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of March 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 14,949 $ 914 $ 15,863 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,683 868 11,551 Total lease payments $ 85,428 $ 3,695 $ 89,123 Less: imputed interest (24,093) (650) (24,743) Present value of lease liabilities $ 61,335 $ 3,045 $ 64,380 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 months ended March 31, 2023 and 2022 was as follows: Three Months Ended March 31, 2023 2022 (dollars in thousands) Lease income $ 1,685 $ 1,645
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 months ended March 31, 2023 and 2022 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 October 31, 2026. 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 March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (274,194) (272,876) Total finance lease assets $ 28,538 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 52,937 $ 52,937 Long-term debt and finance leases due within one year 8,398 8,398 Total finance lease liabilities $ 61,335 $ 61,335 Classification March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 3,032 $ 3,326 Total operating lease assets $ 3,032 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,961 $ 2,256 Other current liabilities 1,084 1,164 Total operating lease liabilities $ 3,045 $ 3,420 Three months ended Lease Cost Classification March 31, 2023 March 31, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,099 $ 1,885 Interest on lease liabilities Interest expense 1,638 1,852 Operating lease cost: Inventory (1) & production expense 329 222 Total leased cost $ 4,066 $ 3,959 (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. March 31, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.69 5.94 Operating leases 6.76 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % Three months ended March 31, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 409 $ 303 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of March 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 14,949 $ 914 $ 15,863 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,683 868 11,551 Total lease payments $ 85,428 $ 3,695 $ 89,123 Less: imputed interest (24,093) (650) (24,743) Present value of lease liabilities $ 61,335 $ 3,045 $ 64,380 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 months ended March 31, 2023 and 2022 was as follows: Three Months Ended March 31, 2023 2022 (dollars in thousands) Lease income $ 1,685 $ 1,645

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	3 Months Ended
	Mar. 31, 2023
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, which was amended on December 9, 2022, in the Superior Court of Fulton County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer, of which we are a co-owner, has 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, one of which remains pending. On December 29, 2022, the Superior Court of Fulton County granted Georgia Power’s motion to transfer the case to the Superior Court of Monroe County. As of the date of this quarterly report, this case has approximately 48 plaintiffs. Eight additional complaints, three on October 8, 2021, four on February 7, 2022, and one on January 9, 2023, 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. Georgia Power has removed each of these cases to the U.S. District Court for the Middle District of Georgia. On November 16, 2022, plaintiffs voluntarily dismissed seven of the cases and, on February 21, 2023 the remaining plaintiff voluntarily dismissed the eighth case. Georgia Power has stated that it anticipates these plaintiffs will refile their complaints. 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 and the announced retirement of Unit No. 3

Restricted Cash and Investments

Restricted Cash and Investments	3 Months Ended
	Mar. 31, 2023
Restricted Investments Note [Abstract]
Restricted Cash and Investments	Restricted Cash and Investments. Restricted investments consisted of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that were held by the U.S. Treasury, acting through the Federal Financing Bank. At December 31, 2022, we had restricted investments totaling $74,031,000, all of which were classified as current. During the three-month period ended March 31, 2023, we utilized all of our restricted investments for scheduled Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. 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 Three months ended March 31, 2023 March 31, 2022 (dollars in thousands) Cash and cash equivalents $ 390,821 $ 467,353 Restricted cash included in restricted cash and short-term investments 16,000 39,200 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 406,821 $ 506,553

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 and December 31, 2022. 2023 2022 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 28,490 $ 29,494 Amortization of financing leases(b) 31,126 31,908 Outage costs(c) 42,421 29,317 Asset retirement obligations—Ashpond and other(l) 378,997 353,212 Asset retirement obligations—Nuclear(l) 275 32,192 Depreciation expense - Plant Vogtle(d) 35,193 35,549 Depreciation expense - Plant Wansley(e) 356,759 361,784 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,811 54,701 Interest rate options cost(g) 138,154 136,827 Deferral of effects on net margin—Smith Energy Facility(h) 135,244 136,730 Other regulatory assets(o) 12,507 10,591 Total Regulatory Assets $ 1,214,977 $ 1,212,305 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 32,587 $ 35,580 Deferral of effects on net margin—Hawk Road Energy Facility(h) 16,482 16,636 Deferral of effects on net margin—Effingham Energy Facility(p) 9,028 14,825 Major maintenance reserve(j) 83,690 74,584 Amortization of financing leases(b) 4,832 5,557 Deferred debt service adder(k) 158,541 154,514 Revenue deferral plan(m) 347,379 357,460 Natural gas hedges(n) 64,584 131,804 Other regulatory liabilities(o) 1,153 1,230 Total Regulatory Liabilities $ 718,276 $ 792,190 Net Regulatory Assets $ 496,701 $ 420,115 (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 21 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 occurred on August 31, 2022. Amortization commenced upon the retirement of Plant Wansley and will 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 the earlier of when Vogtle Unit No. 3 is placed in service or December 2023. (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 allowed 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 contracts. (o) The amortization periods for other regulatory assets range up to 27 years and the amortization periods of other regulatory liabilities range up to 4 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	3 Months Ended
	Mar. 31, 2023
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 2028, with the majority of the balance scheduled to be credited by the end of 2024.

Debt

Debt	3 Months Ended
	Mar. 31, 2023
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 term loan facility (the Facility) under which we borrowed a total of $4,633,028,088. We received our final advance under the Facility in December 2022. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began on February 20, 2020. As of March 31, 2023, we have repaid $363,113,299 of principal on the FFB Notes and the aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled $4,269,914,789. The final maturity date is February 20, 2044. Under the FFB Documents, we may voluntarily prepay outstanding borrowings under the Facility subject to a make-whole premium or discount, as applicable. 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. 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 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 the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve b) Rural Utilities Service Guaranteed Loans: For the three-month period ended March 31, 2023, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $15,431,000 for long-term financing of general and environmental improvements at existing plants. In April 2023, we received an additional $22,970,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Pollution Control Revenue Bonds: On February 1, 2023, we remarketed $99,785,000 of Series 2017 pollution control revenue bonds. The remarketed bonds bear interest at an indexed rate until February 1, 2028 and are scheduled to mature in 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture.

Vogtle Units No. 3 and No. 4 Co

Vogtle Units No. 3 and No. 4 Construction Project	3 Months Ended
	Mar. 31, 2023
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 July 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 $8.67 billion. At March 31, 2023, our total capital and financing costs for our interest in the additional Vogtle units was $8.2 billion, approximately $200 million of which relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power, as described below. The table below shows our project budget and actual costs through March 31, 2023 for our share of the project. (in millions) Project Budget Actual Costs at Construction Costs (1) $ 6,559 $ 6,286 Freeze Capital Credit (2) (532) — Financing Costs 2,038 1,844 Subtotal $ 8,065 $ 8,130 (3) Deferred Training Costs 47 47 Total Project Costs Before Contingency $ 8,112 $ 8,177 Oglethorpe Contingency $ 3 $ — Totals $ 8,115 $ 8,177 (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. (2) As described below, we exercised the tender option to cap our capital costs at the EAC in VCM 19 plus $2.1 billion, the freeze tender threshold. The freeze capital credit reflects our share of budgeted amounts that exceed this threshold. (3) At March 31, 2023, approximately $200 million relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power. 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. Any schedule extension beyond July 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $15-$20 million per month for Unit No. 3 and approximately $10-$15 million per month for Unit No. 4. 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 55 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share would decline from 30% to approximately 27.5%. However, if the total project costs exceed the current budget, our ownership share and megawatts would be further reduced. 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 start-up testing and related test results, engineering support, commodity installation, system turnovers 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. As of March 31, 2023, 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. Future COVID-19 variants could further disrupt or delay construction and testing activities at Vogtle Units No. 3 and No. 4. On March 6, 2023, the Unit No. 3 nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and, on April 1, 2023, the generator successfully synchronized to the power grid and generated electricity for the first time. Operators continue to perform tests at various power levels to help ensure the reactor performs as designed, and Southern Nuclear continues to remediate various equipment and component issues as they are identified. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 during May or June of 2023. While a June 2023 in-service date for Unit No. 3 remains achievable, based on testing progress and remediation work related to valve and flange repairs in the condenser area of the secondary system, we believe that a July 2023 in-service date is more likely and have reflected a July in-service date in our current budget. The projected schedule for Unit No. 3 primarily depends on the progression of pre-operational testing and start-up, which may be impacted by further equipment, component and/or other operational challenges. On May 1, 2023, hot functional testing was completed at Unit No. 4. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 during late fourth quarter 2023 or during the first quarter 2024. 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 in March 2024. Meeting the projected in-service date for Unit No. 4 primarily depends on potential impacts arising from Unit No. 4 testing activities overlapping with Unit No. 3 start-up and commissioning; maintaining overall construction productivity and production levels improving, particularly in subcontractor scopes of work; and maintaining appropriate levels of craft laborers. As Unit No. 4 completes construction and transitions further into testing, ongoing and potential future challenges include the duration of hot functional testing, the timeframe and duration of other testing, the pace and quality of remaining commodities installation; the completion of documentation to support inspections, tests, analyses and acceptance criteria submittals; the pace of remaining work package closures and system turnovers; and the availability of craft, supervisory and technical support resources. Ongoing or future challenges for both units also include management of contractors and vendors; subcontractor performance; and/or related cost escalation. New challenges also may continue to arise as Unit No. 3 completes start-up and commissioning and Unit No. 4 moves further into 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). These challenges may result in further schedule delays and/or cost increases. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. With the receipt of the Nuclear Regulatory Commission’s 103(g) finding in August 2022, Unit No. 3 is now subject to the Nuclear Regulatory Commission’s operating reactor oversight process and must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters, including the timely submittal by Southern Nuclear of the inspections, tests, analyses, and acceptance criteria documentation and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel for Unit No. 4, may arise, which may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria for Unit No. 4, 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 allowed 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 reached $3.4 billion for all Co-owners. As a result of those 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 approximat ely 55 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately 27.5%. By exercising the tender option and based on current assumptions, we estimate that we will avoid incurring approxim ately $535 million in c onstruction costs associated with the project. However, if the total project costs exceed 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. We and Georgia Power do not agree on certain aspects of the tender option, including the dollar amount that triggers our option to tender a portion of our 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 our option to tender was 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. We and Georgia Power also do not agree on the dollar amount that triggered 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 was 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 VCM 19 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. Our lawsuit seeks 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 . Our lawsuit also alleges breach of contract and asserts other claims and seeks damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with our interpretation of the Global Amendments. 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 $8.67 billion, and we would incur approxima tely $535 million of additional construction costs (excluding related financing costs) and retain substantially all of our 30% interest in the additional units. On September 26, 2022, the City of Dalton filed a complaint in our lawsuit and joined our claims. On September 29, 2022, Georgia Power and MEAG reached an agreement with respect to their pending litigation. 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.

Measurement of Credit Losses on

Measurement of Credit Losses on Financial Instruments	3 Months Ended
	Mar. 31, 2023
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

Plant Wansley

Plant Wansley	3 Months Ended
	Mar. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Plant Wansley	Plant Wansley. 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. In accordance with the approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of the remaining plant in service assets associated with Plant Wansley based upon the August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will be recovered through future rates over a period ending 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. Asset Retirement Obligations. On March 6, 2023, Plant Vogtle Unit No. 3's nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality. As a result, as of March 31, 2023, we recognized new nuclear asset retirement obligations totaling $62.8 million. During the three months ended March 31, 2023, we recorded an increase in cash flow estimates of $24.7 million related to existing coal ash related asset retirement obligations. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures.

Asset Retirement Obligations

Asset Retirement Obligations	3 Months Ended
	Mar. 31, 2023
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	Plant Wansley. 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. In accordance with the approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of the remaining plant in service assets associated with Plant Wansley based upon the August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will be recovered through future rates over a period ending 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. Asset Retirement Obligations. On March 6, 2023, Plant Vogtle Unit No. 3's nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality. As a result, as of March 31, 2023, we recognized new nuclear asset retirement obligations totaling $62.8 million. During the three months ended March 31, 2023, we recorded an increase in cash flow estimates of $24.7 million related to existing coal ash related asset retirement obligations. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures.

Recently Issued or Adopted Ac_2

Recently Issued or Adopted Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 2023
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently Issued or Adopted Accounting Pronouncements	Recently Issued or Adopted Accounting Pronouncements. As of March 31, 2023, we have implemented all applicable new accounting standards and updates issued by the Financial Accounting Standards Board (FASB) that were in effect. There were no applicable standards or updates during the three months ended March 31, 2023 that had a material impact on our consolidated financial statements.

Fair Value (Tables)

Fair Value (Tables)	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 and December 31, 2022. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs March 31, 2023 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 219,406 $ 219,406 $ — $ — International equity trust 120,518 — 120,518 — Corporate bonds and debt 64,323 — 64,294 29 US Treasury securities 50,233 50,233 — — Mortgage backed securities 42,029 — 42,029 — Domestic mutual funds 60,724 60,724 — — Federal agency securities 4,243 — 4,243 — International mutual funds 698 — 698 — Non-US Gov't bonds & private placements 2,760 — 2,760 — Other 9,187 9,187 — — Long-term investments: International equity trust 37,645 — 37,645 — Corporate bonds and debt 20,467 — 20,467 — US Treasury securities 16,322 16,322 — — Mortgage backed securities 2,445 — 2,445 — Domestic mutual funds 315,433 315,433 — — Treasury STRIPS 271,338 — 271,338 — Non-US Gov't bonds & private placements 1,960 — 1,960 — Other 400 400 — — Short-term investments: Treasury STRIPS 76,064 — 76,064 — Natural gas swaps 64,584 — 64,584 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2022 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 204,129 $ 204,129 $ — $ — International equity trust 111,266 — 111,266 — Corporate bonds and debt 60,806 — 60,788 18 US Treasury securities 49,775 49,775 — — Mortgage backed securities 41,210 — 41,210 — Domestic mutual funds 57,348 57,348 — — Federal agency securities 2,037 — 2,037 — Non-US Gov't bonds & private placements 2,890 — 2,890 — International mutual funds 653 — 653 — Other 10,602 10,602 — — Long-term investments: International equity trust 33,606 — 33,606 — Corporate bonds and debt 10,473 — 10,473 — US Treasury securities 15,488 15,488 — — Mortgage backed securities 12,113 — 12,113 — Domestic mutual funds 302,302 302,302 — — Treasury STRIPS 293,281 — 293,281 — Non-US Gov't bonds & private placements 1,976 — 1,976 — Other 240 240 — — Short-term investments: Treasury STRIPS 61,702 — 61,702 — Natural gas swaps 131,804 — 131,804 —
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 March 31, 2023 and December 31, 2022 were as follows: 2023 2022 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 11,818,058 $ 10,618,552 $ 11,940,359 $ 10,194,954

Derivative Instruments (Tables)

Derivative Instruments (Tables)	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2023 30.3 2024 30.4 2025 24.9 2026 19.9 2027 7.6 Total 113.1
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 March 31, 2023 and December 31, 2022. Balance Sheet Location Fair Value 2023 2022 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 3,966 $ 35,285 Natural gas swaps Other deferred charges $ 68,232 $ 99,725 Liabilities: Natural gas swaps Other current liabilities $ 7,614 $ 3,206 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 months ended March 31, 2023 and 2022. Statement of Three Months Ended 2023 2022 (dollars in thousands) Natural gas swaps gains Fuel $ 135 $ 8,078 Natural gas swaps losses Fuel (9,397) (79) Total $ (9,262) $ 7,999
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 March 31, 2023 and December 31, 2022. Balance Sheet Location 2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 64,584 $ 131,804 Total $ 64,584 $ 131,804

Investment Securities (Tables)

Investment Securities (Tables)	3 Months Ended
	Mar. 31, 2023
Investments, Debt and Equity Securities [Abstract]
Summary of debt and equity securities	The following tables summarize debt and equity securities as of March 31, 2023 and December 31, 2022. Gross Unrealized (dollars in thousands) March 31, 2023 Cost Gains Losses Fair Equity $ 324,488 $ 191,858 $ (7,030) $ 509,316 Debt 830,095 1,698 (34,803) 796,990 Other 9,885 30 (26) 9,889 Total $ 1,164,468 $ 193,586 $ (41,859) $ 1,316,195 Gross Unrealized (dollars in thousands) December 31, 2022 Cost Gains Losses Fair Equity $ 323,907 $ 159,445 $ (8,949) $ 474,403 Debt 833,035 372 (46,369) 787,038 Other 10,445 20 (9) 10,456 Total $ 1,167,387 $ 159,837 $ (55,327) $ 1,271,897

Revenue Recognition (Tables)

Revenue Recognition (Tables)	3 Months Ended
	Mar. 31, 2023
Revenue from Contract with Customer [Abstract]
Schedule of sales to members and sales to non-members	Sales to members for the three months ended March 31, 2023 and 2022 were as follows: Three Months Ended (dollars in thousands) 2023 2022 Capacity revenues $ 242,043 $ 243,291 Energy revenues 145,610 174,158 Total $ 387,653 $ 417,449 Member energy requirements supplied 64 % 57 % Three Months Ended (dollars in thousands) 2023 2022 Energy revenues $ 1,037 $ 2,993 Capacity revenues 763 — Total $ 1,800 $ 2,993

Leases (Tables)

Leases (Tables)	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (274,194) (272,876) Total finance lease assets $ 28,538 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 52,937 $ 52,937 Long-term debt and finance leases due within one year 8,398 8,398 Total finance lease liabilities $ 61,335 $ 61,335 Classification March 31, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 3,032 $ 3,326 Total operating lease assets $ 3,032 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,961 $ 2,256 Other current liabilities 1,084 1,164 Total operating lease liabilities $ 3,045 $ 3,420
Schedule of lease cost	Three months ended Lease Cost Classification March 31, 2023 March 31, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,099 $ 1,885 Interest on lease liabilities Interest expense 1,638 1,852 Operating lease cost: Inventory (1) & production expense 329 222 Total leased cost $ 4,066 $ 3,959 (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	March 31, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.69 5.94 Operating leases 6.76 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 %
Schedule of cash paid for amounts included in the measurement of lease liabilities	Three months ended March 31, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 409 $ 303 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ —
Schedule of maturities of operating lease liabilities	Maturity analysis of our finance and operating lease liabilities as of March 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 14,949 $ 914 $ 15,863 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,683 868 11,551 Total lease payments $ 85,428 $ 3,695 $ 89,123 Less: imputed interest (24,093) (650) (24,743) Present value of lease liabilities $ 61,335 $ 3,045 $ 64,380
Schedule of maturities of finance lease liabilities	Maturity analysis of our finance and operating lease liabilities as of March 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 14,949 $ 914 $ 15,863 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,683 868 11,551 Total lease payments $ 85,428 $ 3,695 $ 89,123 Less: imputed interest (24,093) (650) (24,743) Present value of lease liabilities $ 61,335 $ 3,045 $ 64,380
Schedule of lessor's income from leases	Lease income recognized during the three months ended March 31, 2023 and 2022 was as follows: Three Months Ended March 31, 2023 2022 (dollars in thousands) Lease income $ 1,685 $ 1,645

Restricted Cash and Investmen_2

Restricted Cash and Investments (Tables)	3 Months Ended
	Mar. 31, 2023
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 Three months ended March 31, 2023 March 31, 2022 (dollars in thousands) Cash and cash equivalents $ 390,821 $ 467,353 Restricted cash included in restricted cash and short-term investments 16,000 39,200 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 406,821 $ 506,553

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 and December 31, 2022. 2023 2022 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 28,490 $ 29,494 Amortization of financing leases(b) 31,126 31,908 Outage costs(c) 42,421 29,317 Asset retirement obligations—Ashpond and other(l) 378,997 353,212 Asset retirement obligations—Nuclear(l) 275 32,192 Depreciation expense - Plant Vogtle(d) 35,193 35,549 Depreciation expense - Plant Wansley(e) 356,759 361,784 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,811 54,701 Interest rate options cost(g) 138,154 136,827 Deferral of effects on net margin—Smith Energy Facility(h) 135,244 136,730 Other regulatory assets(o) 12,507 10,591 Total Regulatory Assets $ 1,214,977 $ 1,212,305 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 32,587 $ 35,580 Deferral of effects on net margin—Hawk Road Energy Facility(h) 16,482 16,636 Deferral of effects on net margin—Effingham Energy Facility(p) 9,028 14,825 Major maintenance reserve(j) 83,690 74,584 Amortization of financing leases(b) 4,832 5,557 Deferred debt service adder(k) 158,541 154,514 Revenue deferral plan(m) 347,379 357,460 Natural gas hedges(n) 64,584 131,804 Other regulatory liabilities(o) 1,153 1,230 Total Regulatory Liabilities $ 718,276 $ 792,190 Net Regulatory Assets $ 496,701 $ 420,115 (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 21 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 occurred on August 31, 2022. Amortization commenced upon the retirement of Plant Wansley and will 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 the earlier of when Vogtle Unit No. 3 is placed in service or December 2023. (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 allowed 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 contracts. (o) The amortization periods for other regulatory assets range up to 27 years and the amortization periods of other regulatory liabilities range up to 4 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)	3 Months Ended
	Mar. 31, 2023
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 March 31, 2023 for our share of the project. (in millions) Project Budget Actual Costs at Construction Costs (1) $ 6,559 $ 6,286 Freeze Capital Credit (2) (532) — Financing Costs 2,038 1,844 Subtotal $ 8,065 $ 8,130 (3) Deferred Training Costs 47 47 Total Project Costs Before Contingency $ 8,112 $ 8,177 Oglethorpe Contingency $ 3 $ — Totals $ 8,115 $ 8,177 (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. (2) As described below, we exercised the tender option to cap our capital costs at the EAC in VCM 19 plus $2.1 billion, the freeze tender threshold. The freeze capital credit reflects our share of budgeted amounts that exceed this threshold. (3) At March 31, 2023, approximately $200 million relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power.

General (Details)

General (Details)	3 Months Ended
	Mar. 31, 2023 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 ($)	3 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Fair value
Nuclear decommissioning trust fund	$ 574,121,000	$ 540,716,000
Long-term investments	666,010,000	669,479,000
Short-term investments	76,064,000	61,702,000
International equity trust
Fair value
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Natural gas swaps
Fair value
Derivative liabilities	$ 64,584,000	131,804,000
Recurring basis | Domestic equity
Fair value
Nuclear decommissioning trust fund	219,406,000	204,129,000
Recurring basis | International equity trust
Fair value
Nuclear decommissioning trust fund	120,518,000	111,266,000
Long-term investments	37,645,000	33,606,000
Recurring basis | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	64,323,000	60,806,000
Long-term investments	20,467,000	10,473,000
Recurring basis | US Treasury securities
Fair value
Nuclear decommissioning trust fund	50,233,000	49,775,000
Long-term investments	16,322,000	15,488,000
Recurring basis | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	42,029,000	41,210,000
Long-term investments	2,445,000	12,113,000
Recurring basis | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	60,724,000	57,348,000
Long-term investments	315,433,000	302,302,000
Recurring basis | Federal agency securities
Fair value
Nuclear decommissioning trust fund	4,243,000	2,037,000
Recurring basis | Treasury STRIPS
Fair value
Long-term investments	271,338,000	293,281,000
Short-term investments	76,064,000	61,702,000
Recurring basis | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,760,000	2,890,000
Long-term investments	1,960,000	1,976,000
Recurring basis | International mutual funds
Fair value
Nuclear decommissioning trust fund	698,000	653,000
Recurring basis | Other
Fair value
Nuclear decommissioning trust fund	9,187,000	10,602,000
Long-term investments	400,000	240,000
Recurring basis | (Level 1) | Natural gas swaps
Fair value
Derivative liabilities	0	0
Recurring basis | (Level 1) | Domestic equity
Fair value
Nuclear decommissioning trust fund	219,406,000	204,129,000
Recurring basis | (Level 1) | International equity trust
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 1) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 1) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	50,233,000	49,775,000
Long-term investments	16,322,000	15,488,000
Recurring basis | (Level 1) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 1) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	60,724,000	57,348,000
Long-term investments	315,433,000	302,302,000
Recurring basis | (Level 1) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | (Level 1) | Treasury STRIPS
Fair value
Long-term investments	0	0
Short-term investments	0	0
Recurring basis | (Level 1) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 1) | International mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | (Level 1) | Other
Fair value
Nuclear decommissioning trust fund	9,187,000	10,602,000
Long-term investments	400,000	240,000
Recurring basis | (Level 2) | Natural gas swaps
Fair value
Derivative liabilities	64,584,000	131,804,000
Recurring basis | (Level 2) | Domestic equity
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | (Level 2) | International equity trust
Fair value
Nuclear decommissioning trust fund	120,518,000	111,266,000
Long-term investments	37,645,000	33,606,000
Recurring basis | (Level 2) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	64,294,000	60,788,000
Long-term investments	20,467,000	10,473,000
Recurring basis | (Level 2) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 2) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	42,029,000	41,210,000
Long-term investments	2,445,000	12,113,000
Recurring basis | (Level 2) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 2) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	4,243,000	2,037,000
Recurring basis | (Level 2) | Treasury STRIPS
Fair value
Long-term investments	271,338,000	293,281,000
Short-term investments	76,064,000	61,702,000
Recurring basis | (Level 2) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,760,000	2,890,000
Long-term investments	1,960,000	1,976,000
Recurring basis | (Level 2) | International mutual funds
Fair value
Nuclear decommissioning trust fund	698,000	653,000
Recurring basis | (Level 2) | Other
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 3) | Natural gas swaps
Fair value
Derivative liabilities	0	0
Recurring basis | (Level 3) | Domestic equity
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | (Level 3) | International equity trust
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 3) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	29,000	18,000
Long-term investments	0	0
Recurring basis | (Level 3) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 3) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 3) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 3) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | (Level 3) | Treasury STRIPS
Fair value
Long-term investments	0	0
Short-term investments	0	0
Recurring basis | (Level 3) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | (Level 3) | International mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | (Level 3) | Other
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	$ 0	$ 0

Fair Value - Estimated fair val

Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Carrying Value
Fair Value
Long-term debt	$ 11,818,058	$ 11,940,359
Fair Value | (Level 2)
Fair Value
Long-term debt	$ 10,618,552	$ 10,194,954

Derivative Instruments - Gas he

Derivative Instruments - Gas hedges (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) MMBTU	Dec. 31, 2022 USD ($)
Derivative Instruments
Derivative asset | $	$ 64,584	$ 131,804
Notional volume of natural gas derivatives (in MMBTUs)	113.1
Three counterparties
Derivative Instruments
Credit collateral posted | $	$ 16,000
One counterparty
Derivative Instruments
Credit collateral posted | $		$ 30,400
2023
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	30.3
2024
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	30.4
2025
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	24.9
2026
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	19.9
2027
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	7.6

Derivative Instruments - Fair v

Derivative Instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022
Assets:
Fair value of assets	$ 64,584	$ 131,804
Other current assets
Assets:
Fair value of assets	3,966	35,285
Other deferred charges
Assets:
Fair value of assets	68,232	99,725
Other current liabilities
Liabilities:
Fair value of liabilities	7,614	3,206
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		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Gains and (losses) on derivative instruments
Net unrealized gains on derivative instruments	$ 64,584		$ 131,804
Natural gas swaps
Gains and (losses) on derivative instruments
Gains	135	$ 8,078
Losses	(9,397)	(79)
Total	(9,262)	$ 7,999
Natural gas swaps | Regulatory liability
Gains and (losses) on derivative instruments
Net unrealized gains on derivative instruments	$ 64,584		$ 131,804

Investment Securities (Details)

Investment Securities (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Cost
Equity	$ 324,488	$ 323,907
Debt	830,095	833,035
Other	9,885	10,445
Total	1,164,468	1,167,387
Gains
Equity	191,858	159,445
Debt	1,698	372
Other	30	20
Total	193,586	159,837
Losses
Equity	(7,030)	(8,949)
Debt	(34,803)	(46,369)
Other	(26)	(9)
Total	(41,859)	(55,327)
Fair Value
Equity	509,316	474,403
Debt	796,990	787,038
Other	9,889	10,456
Total	$ 1,316,195	$ 1,271,897

Revenue Recognition - Additiona

Revenue Recognition - Additional Information (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2023 USD ($) member service	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)
Revenue Recognition
Number of electric distribution cooperative members | member	38
Number of services provided | service	2
Member energy requirements supplied	64%	57%
Margins for interest ratio	1.10
Targeted margins for interest ratio	1.14
Operating revenues	$ 389,453	$ 420,442
Refund liability	0		$ 28,471
Members
Revenue Recognition
Operating revenues	387,653	417,449
Receivables from contracts	126,448		187,401
Non-Members
Revenue Recognition
Operating revenues	1,800	2,993
Capacity revenues | Members
Revenue Recognition
Operating revenues	242,043	243,291
Capacity revenues | Non-Members
Revenue Recognition
Operating revenues	763	0
Energy revenues | Members
Revenue Recognition
Operating revenues	145,610	174,158
Energy revenues | Non-Members
Revenue Recognition
Operating revenues	1,037	$ 2,993
Sale of Effingham Deferring Members' Output | Non-Members
Revenue Recognition
Receivables from contracts	820		8,787
Transactions with Affiliated Companies and Investment Income | Non-Members
Revenue Recognition
Receivables from contracts	$ 35,867		$ 13,834

Revenue Recognition - Managemen

Revenue Recognition - Management Program (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2018
Vogtle Units No. 3 & No. 4
Operating revenues
Amounts billed under rate management program	$ 1,761	$ 3,861
Cumulative recovery of financing costs	128,193
Vogtle New Units
Operating revenues
Cumulative recovery of financing costs	353,389
Rate management program, additional collection period			5 years
Rate management program, billing period			5 years
Amounts billed under additional rate management program	$ 15,713	$ 2,944

Leases - Summary (Details)

Leases - Summary (Details)	3 Months Ended
	Mar. 31, 2023 lease option
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	Mar. 31, 2023	Dec. 31, 2022
Right-of-use assets—Finance leases
Right-of-use assets	$ 302,732	$ 302,732
Less: Accumulated provision for depreciation	(274,194)	(272,876)
Total finance lease assets	$ 28,538	$ 29,856
Finance lease, right-of-use asset, statement of financial position	Right-of-use assets—finance leases	Right-of-use assets—finance leases
Lease liabilities—Finance leases
Obligations under finance leases	$ 52,937	$ 52,937
Long-term debt and finance leases due within one year	8,398	8,398
Total finance lease liabilities	$ 61,335	$ 61,335
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	$ 3,032	$ 3,326
Total operating lease assets	$ 3,032	$ 3,326
Operating lease, right-of-use asset, statement of financial position	In service	In service
Lease liabilities—Operating leases
Capitalization—Other	$ 1,961	$ 2,256
Other current liabilities	1,084	1,164
Total operating lease liabilities	$ 3,045	$ 3,420
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
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Lease Cost
Amortization of leased assets	$ 2,099	$ 1,885
Interest on lease liabilities	1,638	1,852
Operating lease cost:	329	222
Total leased cost	$ 4,066	$ 3,959
Weighted-average remaining lease term (in years)
Finance leases	5 years 8 months 8 days		5 years 11 months 8 days
Operating leases	6 years 9 months 3 days		6 years 5 months 8 days
Weighted-average discount rate:
Finance leases	11.05%		11.05%
Operating leases	5.63%		5.52%

Leases - Other Lease Disclosure

Leases - Other Lease Disclosures (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Lessee
Operating cash flows from operating leases	$ 409	$ 303
Right-of-use assets obtained in exchange for new operating lease liabilities	0	0
Finance Leases
2023	14,949
2024	14,949
2025	14,949
2026	14,949
2027	14,949
Thereafter	10,683
Total lease payments	85,428
Less: imputed interest	(24,093)
Total finance lease liabilities	61,335		$ 61,335
Operating Leases
2023	914
2024	850
2025	641
2026	350
2027	72
Thereafter	868
Total lease payments	3,695
Less: imputed interest	(650)
Total operating lease liabilities	3,045		$ 3,420
Total
2023	15,863
2024	15,799
2025	15,590
2026	15,299
2027	15,021
Thereafter	11,551
Total lease payments	89,123
Less: imputed interest	(24,743)
Present value of lease liabilities	64,380
Lessor
Lease income	$ 1,685	$ 1,645

Contingencies and Regulatory _2

Contingencies and Regulatory Matters (Details)	3 Months Ended
	Mar. 31, 2023 plaintiff
Contingencies and Regulatory Matters
Number of plaintiffs	48

Restricted Cash and Investmen_3

Restricted Cash and Investments - Narrative (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Restricted Investments Note [Abstract]
Restricted investments	$ 74,031
Restricted cash and short-term investments	$ 74,031

Restricted Cash and Investmen_4

Restricted Cash and Investments - Reconciliation of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Thousands	Mar. 31, 2023	Dec. 31, 2022	Mar. 31, 2022	Dec. 31, 2021
Restricted Investments Note [Abstract]
Cash and cash equivalents	$ 390,821	$ 595,381	$ 467,353
Restricted cash included in restricted cash and short-term investments	16,000		39,200
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$ 406,821	$ 625,781	$ 506,553	$ 581,150

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 1,214,977	$ 1,212,305
Total Regulatory Liabilities	718,276	792,190
Net Regulatory Assets	496,701	420,115
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	32,587	35,580
Deferral of effects on net margin - Hawk Road Energy Facility | Hawk Road Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	16,482	16,636
Deferral of effects on net margin - Hawk Road Energy Facility | Effingham Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	9,028	14,825
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	83,690	74,584
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	4,832	5,557
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	158,541	154,514
Revenue deferral plan
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 347,379	357,460
Amortization period, regulatory liability	5 years
Natural gas hedges
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 64,584	131,804
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 1,153	1,230
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization period, regulatory liability	4 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 28,490	29,494
Premium and loss on reacquired debt | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	21 years
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 31,126	31,908
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 42,421	29,317
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	$ 378,997	353,212
Asset retirement obligations | Nuclear
Regulatory Assets and Liabilities
Total Regulatory Assets	275	32,192
Depreciation expense | Plant Vogtle
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 35,193	35,549
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	$ 356,759	361,784
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	55,811	54,701
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	138,154	136,827
Deferral of effects on net margin - Smith Energy Facility | Smith Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Assets	135,244	136,730
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 12,507	$ 10,591
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	27 years

Debt - Department of Energy Loa

Debt - Department of Energy Loan Guarantee (Details)	3 Months Ended
	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Mar. 22, 2019 USD ($)	Feb. 20, 2014 USD ($) note
Debt
Repayments of long-term debt	$ 137,732,000	$ 115,168,000
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 | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 4,269,914,789
Long-term debt | FFB
Debt
Number of future advance promissory notes | note				2
Maximum borrowing capacity			$ 1,619,679,706	$ 3,057,069,461
Maximum borrowing capacity designated for capitalized interest				$ 4,633,028,088
Repayments of long-term debt	$ 363,113,299
Long-term debt | FFB | Department of Energy guarantee | Services Agreement
Debt
Guarantee payment			$ 4,676,749,167

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	3 Months Ended
	Apr. 30, 2023	Mar. 31, 2023
Debt
Advances received on loans		$ 15,431
Subsequent Event
Debt
Advances received on loans	$ 22,970

Debt - Pollution Control Revenu

Debt - Pollution Control Revenue Bonds (Details) $ in Thousands	Feb. 01, 2023 USD ($)
Municipal bonds | Series 2017 Pollution Control Revenue Bonds
Debt
Debt instrument, face amount	$ 99,785

Vogtle Units No. 3 and No. 4 _3

Vogtle Units No. 3 and No. 4 Construction Project - Narrative (Details) $ in Millions		3 Months Ended
	Feb. 18, 2019 USD ($)	Mar. 31, 2023 USD ($) unit MW	Dec. 31, 2021 USD ($)
Loan Guarantee Agreement
Public Utility Property Plant and Equipment
Term of debt		5 years
Vogtle Units No. 3 & No. 4
Public Utility Property Plant and Equipment
Total investment in additional Vogtle units		$ 8,200
Investment in excess of tender option		$ 200
Ownership interest (as a percent)		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		55
Proportionate ownership share with exercise of tender option (as a percent)		27.50%
Total project cost		$ 8,115
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 | 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 | Ownership participation agreement
Public Utility Property Plant and Equipment
Project budget		$ 8,100
Project budget had tender option not been exercised		$ 8,670
Ownership share, generating capacity (in megawatts) | MW		660
Construction cost savings due to exercise of tender option		$ 535
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		8,670
Total project cost		18,380
Increase in project budget based on Georgia Power's interpretation		$ 535
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 3 | Minimum
Public Utility Property Plant and Equipment
Monthly delay cost, exercise of tender option		$ 15
Vogtle Unit Number 3 | Maximum
Public Utility Property Plant and Equipment
Monthly delay cost, exercise of tender option		20
Vogtle Unit Number 4 | Minimum
Public Utility Property Plant and Equipment
Monthly delay cost, exercise of tender option		10
Vogtle Unit Number 4 | Maximum
Public Utility Property Plant and Equipment
Monthly delay cost, exercise of tender option		$ 15

Vogtle Units No. 3 and No. 4 _4

Vogtle Units No. 3 and No. 4 Construction Project - Project Budget and Actual Costs (Details) - Vogtle Units No. 3 & No. 4 - USD ($) $ in Millions		3 Months Ended
	Feb. 18, 2019	Mar. 31, 2023
Actual Costs
Proceeds from guarantee agreement		$ 1,100
Cost sharing benefits		99
Investment in excess of tender option		200
Global Amendments To Term Sheet
Project Budget
Totals		17,100
Actual Costs
Additional construction costs	$ 800
Financial Exposure Term Two | Maximum | Global Amendments To Term Sheet
Actual Costs
Additional construction costs	$ 2,100
Jointly Owned Nuclear Power Plant
Project Budget
Construction Costs		6,559
Freeze Capital Credit		(532)
Financing Costs		2,038
Subtotal		8,065
Deferred Training Costs		47
Total Project Costs Before Contingency		8,112
Oglethorpe Contingency		3
Totals		8,115
Actual Costs
Construction Costs		6,286
Freeze Capital Credit		0
Financing Costs		1,844
Subtotal		8,130
Deferred Training Costs		47
Total Project Costs Before Contingency		8,177
Oglethorpe Contingency		0
Totals		8,177
Jointly Owned Nuclear Power Plant | Global Amendments To Term Sheet
Project Budget
Totals		$ 17,100

Plant Wansley (Details)

Plant Wansley (Details)	Jul. 31, 2022
Plant Wansley
Asset Retirement Obligation [Line Items]
Ownership interest (as a percent)	30%

Asset Retirement Obligations -

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Asset Retirement Obligation [Line Items]
Change in asset retirement obligations	$ 87,509	$ 0
Ashpond and other
Asset Retirement Obligation [Line Items]
Change in asset retirement obligations	24,700
Vogtle Unit Number 3
Asset Retirement Obligation [Line Items]
Cost to close plant	$ 62,800