Oglethorpe Power S-4 29 Mar 23 Registration of securities issued in business combination transactions Financial data

Cover Page

Cover Page	12 Months Ended
	Dec. 31, 2022
Cover [Abstract]
Document Type	S-4
Entity Registrant Name	Oglethorpe Power Corporation
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0000788816
Amendment Flag	false

CONSOLIDATED STATEMENTS OF REVE

CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Operating revenues:
Total operating revenues	$ 2,130,137	$ 1,604,863	$ 1,377,618
Operating expenses:
Fuel	1,045,089	598,996	360,254
Production	468,754	410,708	427,808
Depreciation and amortization	283,774	275,346	248,888
Purchased power	82,516	69,346	68,484
Accretion	55,953	56,086	54,475
Total operating expenses	1,936,086	1,410,482	1,159,909
Operating margin	194,051	194,381	217,709
Other income:
Investment income	57,564	45,932	43,294
Amortization of deferred gains	1,789	1,789	1,789
Allowance for equity funds used during construction	700	385	374
Other	12,191	23,148	5,238
Total other income	72,244	71,254	50,695
Interest charges:
Interest expense	455,474	417,722	409,145
Allowance for debt funds used during construction	(262,573)	(221,463)	(207,972)
Amortization of debt discount and expense	11,690	11,595	11,336
Net interest charges	204,591	207,854	212,509
Net margin	61,704	57,781	55,895
Members
Operating revenues:
Total operating revenues	1,974,683	1,557,109	1,377,010
Non-Members
Operating revenues:
Total operating revenues	$ 155,454	$ 47,754	$ 608

CONSOLIDATED BALANCE SHEETS

CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Electric plant:
In service	$ 9,266,627	$ 9,865,660
Right-of-use assets - finance leases	302,732	302,732
Less: Accumulated provision for depreciation	(5,183,589)	(5,565,724)
Electric plant in service, net	4,385,770	4,602,668
Nuclear fuel, at amortized cost	388,303	375,267
Construction work in progress	7,716,035	6,779,392
Total electric plant	12,490,108	11,757,327
Investments and funds:
Nuclear decommissioning trust fund	540,716	659,910
Investment in associated companies	78,937	75,826
Long-term investments	669,479	711,379
Restricted investments	0	73,702
Other	32,561	31,991
Total investments and funds	1,321,693	1,552,808
Current assets:
Cash and cash equivalents	595,381	579,350
Restricted cash and short-term investments	104,431	246,350
Short-term investments	61,702	0
Receivables	220,015	159,538
Inventories, at average cost	297,951	260,526
Prepayments and other current assets	51,409	62,286
Total current assets	1,330,889	1,308,050
Deferred charges and other assets:
Regulatory assets	1,212,305	1,008,790
Prepayments to Georgia Power Company	20,873	27,124
Other	113,502	52,927
Total deferred charges	1,346,680	1,088,841
Total assets	16,489,370	15,707,026
Capitalization:
Patronage capital and membership fees	1,192,127	1,130,423
Long-term debt	11,512,513	10,529,449
Obligations under finance leases	52,937	61,335
Obligation under Rocky Mountain transactions	27,945	26,151
Other	2,256	1,550
Total capitalization	12,787,778	11,748,908
Current liabilities:
long-term debt and finance leases due within one year	322,102	281,238
Short-term borrowings	655,650	1,095,971
Accounts payable	203,705	182,164
Accrued interest	105,452	96,410
Member power bill prepayments, current	54,443	26,102
Other current liabilities	153,941	36,123
Total current liabilities	1,495,293	1,718,008
Deferred credits and other liabilities:
Asset retirement obligations	1,343,743	1,287,143
Member power bill prepayments, non-current	53,877	80,001
Regulatory liabilities	792,190	849,449
Other	16,489	23,517
Total deferred credits and other liabilities	2,206,299	2,240,110
Total equity and liabilities	16,489,370	15,707,026
Commitments and Contingencies (Notes 1, 7, 10, 11 and 12)

CONSOLIDATED STATEMENTS OF CAPI

CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Secured Long-term debt:
Total Secured Long-term debt	$ 11,940,359	$ 10,915,054
Obligations under finance leases	61,335	68,876
Obligation under Rocky Mountain transactions	27,945	26,151
Other	2,256	1,550
Patronage capital and membership fees	1,192,127	1,130,423
Subtotal	13,224,022	12,142,054
Less: long-term debt and finance leases due within one year	(322,102)	(281,238)
Less: unamortized debt issuance costs	(96,588)	(95,883)
Less: unamortized bond discounts on long-term debt	(17,554)	(16,025)
Total capitalization	12,787,778	11,748,908
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.03% to 8.21% (average rate of 3.40% at December 31, 2022) due in quarterly installments through 2048
Secured Long-term debt:
Total Secured Long-term debt	2,758,753	2,601,365
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.44% to 4.01% (average rate of 2.94% at December 31, 2022) due in quarterly installments through 2044
Secured Long-term debt:
Total Secured Long-term debt	4,325,395	3,925,493
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035
Secured Long-term debt:
Total Secured Long-term debt	$ 300,000	300,000
Interest rate (as a percent)	5.534%
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031
Secured Long-term debt:
Total Secured Long-term debt	$ 500,000	500,000
Interest rate (as a percent)	6.191%
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039
Secured Long-term debt:
Total Secured Long-term debt	$ 400,000	400,000
Interest rate (as a percent)	5.95%
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024
Secured Long-term debt:
Total Secured Long-term debt	$ 2,021	3,031
Interest rate (as a percent)	1.81%
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040
Secured Long-term debt:
Total Secured Long-term debt	$ 450,000	450,000
Interest rate (as a percent)	5.375%
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050
Secured Long-term debt:
Total Secured Long-term debt	$ 300,000	300,000
Interest rate (as a percent)	5.25%
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042
Secured Long-term debt:
Total Secured Long-term debt	$ 250,000	250,000
Interest rate (as a percent)	4.20%
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044
Secured Long-term debt:
Total Secured Long-term debt	$ 250,000	250,000
Interest rate (as a percent)	4.55%
Public | First mortgage bonds payable: Series 2016A First Mortgage Bonds, 4.25% due 2046
Secured Long-term debt:
Total Secured Long-term debt	$ 250,000	250,000
Interest rate (as a percent)	4.25%
Public | First Mortgage Bonds Payable: Series 2018A First Mortgage Bonds, 5.05% Due 2048
Secured Long-term debt:
Total Secured Long-term debt	$ 500,000	500,000
Interest rate (as a percent)	5.05%
Public | First Mortgage Bonds Payable Series 2020A First Mortgage Bonds, 3.75% Due 2048
Secured Long-term debt:
Total Secured Long-term debt	$ 450,000	450,000
Interest rate (as a percent)	3.75%
Public | First Mortgage Bonds Payable Series 2022A First Mortgage Bonds, 4.50% Due 2047
Secured Long-term debt:
Total Secured Long-term debt	$ 500,000	0
Interest rate (as a percent)	4.50%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2013A Appling, Burke and Monroe, Term rate bonds, 1.50% through April 1, 2020, due 2038 through 2040
Secured Long-term debt:
Total Secured Long-term debt	$ 212,760	212,760
Interest rate (as a percent)	1.50%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A, B Burke, Indexed put bonds - weekly reset, 4.61% due 2040 through 2045
Secured Long-term debt:
Total Secured Long-term debt	$ 91,645	122,620
Interest rate (as a percent)	4.61%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 C, D Burke, Remarketed in 2018 to fixed rate bonds, 4.125%, due 2041 through 2045
Secured Long-term debt:
Total Secured Long-term debt	$ 200,000	200,000
Interest rate (as a percent)	4.125%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017E Burke, Remarketed in 2018 to term rate bonds, 3.25% through February 3, 2025, due 2041 through 2045
Secured Long-term debt:
Total Secured Long-term debt	$ 100,000	100,000
Interest rate (as a percent)	3.25%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 F Burke, Remarketed in 2018 to term rate bonds, 3.00% through February 1, 2023, due 2041 through 2045
Secured Long-term debt:
Total Secured Long-term debt	$ 99,785	$ 99,785
Interest rate (as a percent)	3%

CONSOLIDATED STATEMENTS OF CA_2

CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical)	Dec. 31, 2022
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.03% to 8.21% (average rate of 3.40% at December 31, 2022) due in quarterly installments through 2048
Secured Long-term debt:
Interest rate, average rate (as a percent)	3.40%
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.03% to 8.21% (average rate of 3.40% at December 31, 2022) due in quarterly installments through 2048 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	1.03%
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.03% to 8.21% (average rate of 3.40% at December 31, 2022) due in quarterly installments through 2048 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	8.21%
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.44% to 4.01% (average rate of 2.94% at December 31, 2022) due in quarterly installments through 2044
Secured Long-term debt:
Interest rate, average rate (as a percent)	2.94%
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.44% to 4.01% (average rate of 2.94% at December 31, 2022) due in quarterly installments through 2044 | Minimum
Secured Long-term debt:
Interest rate (as a percent)	1.44%
Federal Financing Bank (FFB) | First mortgage notes payable to the Federal Financing Bank at interest rates varying from 1.44% to 4.01% (average rate of 2.94% at December 31, 2022) due in quarterly installments through 2044 | Maximum
Secured Long-term debt:
Interest rate (as a percent)	4.01%
Public | First mortgage bonds payable: Series 2006 First Mortgage Bonds, 5.534%, due 2031 through 2035
Secured Long-term debt:
Interest rate (as a percent)	5.534%
Public | First mortgage bonds payable: Series 2007 First Mortgage Bonds, 6.191%, due 2024 through 2031
Secured Long-term debt:
Interest rate (as a percent)	6.191%
Public | First mortgage bonds payable: Series 2009B First Mortgage Bonds, 5.95%, due 2039
Secured Long-term debt:
Interest rate (as a percent)	5.95%
Public | First mortgage bonds payable: Series 2009 Clean renewable energy bond, 1.81%, due 2024
Secured Long-term debt:
Interest rate (as a percent)	1.81%
Public | First mortgage bonds payable: Series 2010A First Mortgage Bonds, 5.375% due 2040
Secured Long-term debt:
Interest rate (as a percent)	5.375%
Public | First mortgage bonds payable: Series 2011A First Mortgage Bonds, 5.25% due 2050
Secured Long-term debt:
Interest rate (as a percent)	5.25%
Public | First mortgage bonds payable: Series 2012A First Mortgage Bonds, 4.20% due 2042
Secured Long-term debt:
Interest rate (as a percent)	4.20%
Public | First mortgage bonds payable: Series 2014A First Mortgage Bonds, 4.55% due 2044
Secured Long-term debt:
Interest rate (as a percent)	4.55%
Public | First mortgage bonds payable: Series 2016A First Mortgage Bonds, 4.25% due 2046
Secured Long-term debt:
Interest rate (as a percent)	4.25%
Public | First Mortgage Bonds Payable: Series 2018A First Mortgage Bonds, 5.05% Due 2048
Secured Long-term debt:
Interest rate (as a percent)	5.05%
Public | First Mortgage Bonds Payable Series 2020A First Mortgage Bonds, 3.75% Due 2048
Secured Long-term debt:
Interest rate (as a percent)	3.75%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: 2013A Appling, Burke and Monroe, Term rate bonds, 1.50% through April 1, 2020, due 2038 through 2040
Secured Long-term debt:
Interest rate (as a percent)	1.50%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 A, B Burke, Indexed put bonds - weekly reset, 4.61% due 2040 through 2045
Secured Long-term debt:
Interest rate (as a percent)	4.61%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 C, D Burke, Remarketed in 2018 to fixed rate bonds, 4.125%, due 2041 through 2045
Secured Long-term debt:
Interest rate (as a percent)	4.125%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017E Burke, Remarketed in 2018 to term rate bonds, 3.25% through February 3, 2025, due 2041 through 2045
Secured Long-term debt:
Interest rate (as a percent)	3.25%
Georgia Development Authorities | First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 F Burke, Remarketed in 2018 to term rate bonds, 3.00% through February 1, 2023, due 2041 through 2045
Secured Long-term debt:
Interest rate (as a percent)	3%

CONSOLIDATED STATEMENTS OF CASH

CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net margin	$ 61,704	$ 57,781	$ 55,895
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	451,899	400,681	376,639
Accretion cost	55,953	56,086	54,475
Amortization of deferred gains	(1,789)	(1,789)	(1,789)
Allowance for equity funds used during construction	(700)	(385)	(374)
Deferred outage costs	(30,926)	(30,746)	(38,278)
Loss (gain) on sale of investments	21,950	(13,516)	(19,779)
Gain on sale of spare parts	0	(15,734)	0
Regulatory deferral of costs associated with nuclear decommissioning	(54,529)	(19,318)	(10,691)
Other	(712)	(2,528)	(5,587)
Change in operating assets and liabilities:
Receivables	(68,550)	(5,693)	(3,659)
Inventories	(36,235)	23,232	(2,409)
Prepayments and other current assets	25,031	577	(23,754)
Accounts payable	7,008	31,790	1,504
Accrued interest	9,042	23,976	6,539
Accrued taxes	52,764	(36,301)	33,588
Other current liabilities	32,300	(14,292)	9,439
Member power bill prepayments	2,217	(38,078)	(67,281)
Rate management program collections, net	19,847	144,763	146,917
Total adjustments	484,570	502,725	455,500
Net cash provided by operating activities	546,274	560,506	511,395
Cash flows from investing activities:
Property additions	(1,156,383)	(1,203,050)	(1,335,380)
Plant acquisition	(86,826)	(233,156)	0
Activity in nuclear decommissioning trust fund - Purchases	(204,500)	(675,153)	(578,610)
Activity in nuclear decommissioning trust fund - Proceeds	194,046	667,344	570,294
Proceeds from the sale of spare parts	0	18,500	0
Decrease in restricted investments	246,022	167,535	46,003
Activity in other long-term investments - Purchases	(185,092)	(433,532)	(425,628)
Activity in other long-term investments - Proceeds	107,082	246,256	186,219
Other	4,040	14,843	7,982
Net cash used in investing activities	(1,081,611)	(1,430,413)	(1,529,120)
Cash flows from financing activities:
Long-term debt proceeds	1,414,925	757,032	2,221,685
Long-term debt payments	(397,162)	(468,577)	(1,334,368)
(Decrease) increase in short-term borrowings, net	(440,321)	712,473	101,128
Other	2,526	44,618	(13,821)
Net cash provided by financing activities	579,968	1,045,546	974,624
Net increase (decrease) in cash, cash equivalents and restricted cash	44,631	175,639	(43,101)
Cash, cash equivalents and restricted cash at beginning of period	581,150	405,511	448,612
Cash, cash equivalents and restricted cash at end of period	625,781	581,150	405,511
Cash paid for -
Interest (net of amounts capitalized)	182,066	170,605	193,063
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	10,486	107,677	18,709
Accrued property additions at end of period	$ 79,204	$ 65,686	$ 89,640

CONSOLIDATED STATEMENTS OF PATR

CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Increase (Decrease) in Members' Capital
Net margin	$ 61,704	$ 57,781	$ 55,895
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Beginning balance	1,130,423	1,072,642	1,016,747
Net margin	61,704	57,781	55,895
Ending balance	$ 1,192,127	$ 1,130,423	$ 1,072,642

Summary of significant accounti

Summary of significant accounting policies	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Summary of significant accounting policies	1. Summary of significant accounting policies: a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,744 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 733 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 584 megawatts of capacity, including 552 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.4 million people. b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. Certain prior year amounts have been reclassified to conform with current year presentation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2022 and 2021 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2022. Examples of estimates used include items related to our asset retirement obligations. Accounting for asset retirement and environmental obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Estimating the amount and timing of future expenditures includes, among other things, making projections of when assets will be retired and ultimately decommissioned, the amount of decommissioning costs, and how costs will escalate with inflation. Actual results could differ from those estimates. c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation resources. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities. d. Margin policy 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 the years 2022, 2021 and 2020, we achieved a margins for interest ratio of 1.14. e. 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 sell energy and capacity to non-members through industry standard contracts and negotiated agreements, respectively. 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 its 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 December 31, 2022, we did not have any significant long-term contracts with non-members. The consideration we receive for providing capacity services to our members 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 1q. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our member capacity revenues are based on the associated costs we expect to recover in a given year and are 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 1p. 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. In 2022, 2021 and 2020, we provided approximately 58%, 62% 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 2022, 2021 and 2020, our board approved, and we achieved, a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of December 31, 2022 and December 31, 2021, we recognized refund liabilities totaling $28,471,000 and $30,029,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ 2020 ​ ​ (dollars in thousands) Capacity revenues ​ $ 984,036 ​ $ 946,662 ​ $ 971,071 Energy revenues ​ 990,647 ​ 610,447 ​ 405,939 Total ​ $ 1,974,683 ​ $ 1,557,109 ​ $ 1,377,010 ​ The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2022, 2021 or 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 Jackson EMC 16.0 % 15.2 % 15.2 % GreyStone Power Corporation, an EMC 10.0 % 8.7 % 8.7 % Cobb EMC 9.5 % 12.3 % 13.2 % ​ Receivables from contracts with our members at December 31, 2022 and December 31, 2021 were $187,401,000 and $143,715,000, respectively. Energy revenues from non-members were primarily due from the sale of the Effingham deferring members’ output into the wholesale market. In 2022, we recognized capacity revenues from non-members relating to our Washington County acquisition. For additional information regarding the Washington County acquisition, see Note 14. Sales to non-members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 ​ ​ (dollars in thousands) Energy revenues ​ $ 155,372 ​ $ 47,754 ​ $ 608 Capacity revenues ​ 82 ​ — ​ — Total ​ $ 155,454 ​ $ 47,754 ​ $ 608 ​ 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 in 2022, 2021 and 2020 were $14,796,000, $15,693,000 and $14,684,000, respectively. The cumulative amount billed since inception of the program totaled $126,432,000. In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. During the first quarter of 2022, we began applying billing credits to some of our participating members within this program. Under this program, amounts billed to participating members, net of credits, during 2022, 2021 and 2020 were $11,774,000, $143,000,000 and $125,842,000 respectively. Funds collected through this program are invested and held until applied to members’ bills. Investments that mature and are expected to be applied to members’ bills within the next twelve months are included in the Short-term investments line item within our consolidated balance sheets. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members’ bills. The net cumulative amount billed since inception of the program totaled $369,102,000. f. Receivables A substantial portion of our receivables are related to capacity and energy sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Receivables from contracts with our members at December 31, 2022, 2021 and 2020 were $187,401,000, $143,715,000 and $135,462,000, respectively. Payment is typically received the following month in which capacity and energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. The remainder of our receivables is primarily related to transactions with non-members from the sale of the Effingham deferring members’ output, affiliated companies and investment income. Our receivables from non-members were $32,614,000 at December 31, 2022. Our receivables from non-members were insignificant at December 31, 2021. As a result of our historical experience, the short duration lifetime of our receivables and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of our receivables is remote. During 2022, 2021 and 2020, no credit losses were recognized on any receivables that arose from contracts with members or non-members. g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2022, 2021 and 2020 amounted to $73,871,000, $77,366,000, and $75,968,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. Georgia Power filed claims against the U.S. government in 2014 (as amended) seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2011 through December 31, 2014. On June 12, 2019, the U.S. Court of Federal Claims granted Georgia Power’s motion for summary judgement on damages not disputed by the U.S. Government and awarded the undisputed damages to Georgia Power. However, these undisputed damages are not collectable by Georgia Power and no amounts will be recognized in our financial statements until the court enters final judgement on the remaining damages. Georgia Power filed additional claims against the U.S. government in 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2015 through December 31, 2017. On August 13, 2020, Georgia Power filed amended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for damages from January 1, 2018 to December 31, 2019. Our share of the claims outstanding for the period January 1, 2011 through December 31, 2019 are approximately $84,000,000. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the consolidated financial statements as of December 31, 2022 or December 31, 2021 for these claims. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant. h. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset’s future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities and coal ash ponds. In addition, we have retirement obligations related to gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants’ asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2021 and 2022, respectively. The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Coal Ash Pond Other Total ​ ​ (dollars in thousands) Balance at December 31, 2021 ​ $ 778,214 ​ $ 442,686 ​ $ 66,243 ​ 1,287,143 Liabilities settled ​ — ​ (10,134) ​ (184) ​ (10,318) Accretion ​ 41,892 ​ 12,196 ​ 1,865 ​ 55,953 Deferred accretion ​ — ​ 479 ​ — ​ 479 Change in cash flow estimates ​ — ​ 16,301 ​ (5,815) ​ 10,486 Balance at December 31, 2022 ​ $ 820,106 ​ $ 461,528 ​ $ 62,109 ​ $ 1,343,743 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Coal Ash Pond Other Total ​ ​ (dollars in thousands) Balance at December 31, 2020 ​ $ 738,217 ​ $ 346,589 ​ $ 51,177 ​ $ 1,135,983 Liabilities settled ​ — ​ (17,046) ​ 4,642 ​ (12,404) Accretion ​ 43,206 ​ 11,157 ​ 1,723 ​ 56,086 Deferred accretion ​ — ​ (199) ​ — ​ (199) Change in cash flow estimates ​ (3,209) ​ 102,185 ​ 8,701 ​ 107,677 Balance at December 31, 2021 ​ $ 778,214 ​ $ 442,686 ​ $ 66,243 ​ $ 1,287,143 ​ Asset Retirement Obligations Nuclear Decommissioning. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hatch Hatch Vogtle Vogtle 2021 site study ​ Unit No. 1 ​ Unit No. 2 ​ Unit No. 1 ​ Unit No. 2 Expected start date of decommissioning 2034 2038 2047 2049 ​ ​ (dollars in thousands) Estimated costs based on site study in 2021 dollars: ​ ​ ​ ​ Radiated structures ​ $ 227,000 ​ $ 236,000 ​ $ 200,000 ​ $ 213,000 Spent fuel management ​ 60,000 ​ 51,000 ​ 58,000 ​ 53,000 Non-radiated structures ​ 15,000 ​ 21,000 ​ 24,000 ​ 31,000 Total estimated site study costs ​ $ 302,000 ​ $ 308,000 ​ $ 282,000 ​ $ 297,000 ​ We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment. Coal Combustion Residuals. We have internally segregated the funds collected for coal ash pond and other CCR decommissioning costs, including earnings thereon. As of December 31, 2022 and December 31, 2021, the fund balances were $153,208,000 and $140,474,000, respectively. We apply the provision of regulated operations to coal ash pond and other CCR decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) are compared to the associated decommissioning expenses with the difference deferred to or amortized from the regulatory asset. This difference is recorded to the associated expenses in our consolidated statements of revenues and expenses. Unrealized gains and losses of the associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment. Other Retirement Costs Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q. i. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC’s regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2022, additional amounts totaling $2,643,000 were contributed to the external trust funds. In 2021, no additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance sheets. In 2022 we contributed $8,350,000 into the internal funds and in 2021 we contributed $9,750,000 into the internal funds. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2022 and December 31, 2021. The funds were invested in a diversified mix of approximately 69% equity and 31% fixed income securities in 2022 and 71% equity and 29% fixed income securities in 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 External Trust Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2021 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2022 ​ ​ (dollars in thousands) Equity ​ $ 223,336 ​ $ 9,255 ​ $ (3,655) ​ $ 131,572 ​ $ 360,508 Debt ​ 204,935 ​ 191,958 ​ (203,907) ​ (12,869) ​ 180,117 Other ​ (795) ​ 3,287 ​ (2,401) ​ — ​ 91 ​ ​ $ 427,476 ​ $ 204,500 ​ $ (209,963) ​ $ 118,703 ​ $ 540,716 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $ 5,463,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 Internal Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2021 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2022 ​ ​ (dollars in thousands) Equity ​ $ 68,914 ​ $ — ​ $ 10,005 ​ $ 18,995 ​ $ 97,914 Debt ​ 46,856 ​ 76,207 ​ (79,828) ​ (2,741) ​ 40,494 ​ ​ $ 115,770 ​ $ 76,207 ​ $ (69,823) ​ $ 16,254 ​ $ 138,408 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $ 6,384,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 External Trust Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2020 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2021 ​ ​ (dollars in thousands) Equity ​ $ 212,387 ​ $ 50,309 ​ $ (39,360) ​ $ 230,710 ​ $ 454,046 Debt ​ 196,810 ​ 583,003 ​ (574,878) ​ 1,724 ​ 206,659 Other ​ 17 ​ 41,841 ​ (42,653) ​ — ​ (795) ​ ​ $ 409,214 ​ $ 675,153 ​ $ (656,891) ​ $ 232,434 ​ $ 659,910 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $ 18,261,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 Internal Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2020 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2021 ​ ​ (dollars in thousands) Equity ​ $ 50,647 ​ $ — ​ $ 18,267 ​ $ 44,735 ​ $ 113,649 Debt ​ 50,467 ​ 204,150 ​ (207,761) ​ 181 ​ 47,037 ​ ​ $ 101,114 ​ $ 204,150 ​ $ (189,494) ​ $ 44,916 ​ $ 160,686 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $ 14,656,000 . Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. The nuclear decommissioning trust fund has produced an average annualized return of approximately 5.9% in the last ten years and 5.8% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the above assumption, our management believes that increases in cost estimates of decommissioning can be recovered in future rates. j. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use prescribed depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The depreciation rates for steam, nuclear and other production in the table below reflect revised rates from depreciation rate studies completed in 2020 or 2021. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2022, 2021, and 2020 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Remaining Useful ​ ​ ​ ​ ​ Life Range in ​ ​ ​ ​ ​ ​ ​ ​ years* ​ 2022 ​ 2021 ​ 2020 Steam production 20-22 13.77 % 14.47 % 2.58 % Nuclear production 12-27 2.17 % 2.18 % 1.93 % Hydro production 44 2.00 % 2.00 % 2.00 % Other production 17-26 2.68 % 2.60 % 2.61 % Transmission 12-27 2.75 % 2.75 % 2.75 % General 1-43 2.00 - 33.33 % 2.00-33.33 % 2.00-33.33 % * Based on estimated retirement dates as of 2022. Actual retirement dates may be different. Remaining useful lives for nuclear production are based on the expiration date of the applicable operating license approved by the NRC. Depreciation expense for the years 2022, 2021 and 2020 was $278,452,000, $269,280,000, and $242,822,000, respectively. In 2021, the composite depreciation rate for Plant Wansley was increased in anticipation of the plant’s retirement in 2022. In addition to the depreciation expense recognized in 2022 and 2021, $165,013,000 k. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years 2022, 2021 and 2020, the allowance for funds used during construction rates were 4.03%, 3.90% and 4.00%, respectively. Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants. l. Cash and cash equivalents We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments. m. Restricted cash and investments Restricted investments consist of funds on

Fair Value

Fair Value	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Fair Value	2. 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. Assets and liabilities measured at fair value are based on one or more of the following three valuation techniques: (1) Market approach. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs. (2) Income approach. The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. (3) Cost approach. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility adjusted for obsolescence. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using ​ ​ ​ Quoted Prices in ​ ​ ​ ​ ​ ​ ​ ​ ​ Active Markets for ​ Significant Other ​ Significant ​ ​ December 31, ​ Identical Assets ​ Observable Inputs ​ Unobservable Inputs ​ ​ 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 ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using ​ ​ ​ Quoted Prices in Significant Other Significant ​ ​ ​ ​ ​ Active Markets for ​ Observable ​ Unobservable ​ ​ December 31, ​ Identical Assets ​ Inputs ​ Inputs ​ ​ 2021 ​ (Level 1) ​ (Level 2) ​ (Level 3) ​ (dollars in thousands) Nuclear decommissioning trust funds: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Domestic equity ​ $ 249,999 ​ $ 249,999 ​ $ — ​ $ — International equity trust ​ $ 140,718 ​ — ​ 140,718 ​ — Corporate bonds and debt ​ $ 72,936 ​ — ​ 72,369 ​ 567 US Treasury securities ​ $ 53,321 ​ 53,321 ​ — ​ — Mortgage backed securities ​ $ 40,460 ​ — ​ 40,460 ​ — Domestic mutual funds ​ $ 75,384 ​ 75,384 ​ — ​ — Municipal bonds ​ $ 1,133 ​ — ​ 1,133 ​ — Federal agency securities ​ $ 9,608 ​ — ​ 9,608 ​ — Other ​ $ 16,351 ​ 13,623 ​ 2,728 ​ — Long-term investments: ​ ​ ​ ​ International equity trust ​ $ 35,873 ​ — ​ 35,873 ​ — Corporate bonds and debt ​ $ 14,022 ​ — ​ 12,656 ​ 1,366 US Treasury securities ​ $ 15,259 ​ 15,259 ​ — ​ — Mortgage backed securities ​ $ 12,021 ​ — ​ 12,021 ​ — Domestic mutual funds ​ $ 277,937 ​ 277,937 ​ — ​ — Federal agency securities ​ $ 257 ​ — ​ 257 ​ — Treasury STRIPS ​ $ 350,532 ​ — ​ 350,532 ​ — Other ​ $ 5,478 ​ 5,478 ​ — ​ — Natural gas swaps ​ $ 63,994 ​ — ​ 63,994 ​ — ​ The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed 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. 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 December 31, 2022 and 2021 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ Carrying Fair Carrying Fair ​ ​ Value ​ Value ​ Value ​ Value ​ ​ (in thousands) Long-term debt ​ $ 11,940,359 ​ $ 10,194,954 ​ $ 10,915,054 ​ $ 12,741,046 ​ The estimated fair value of long-term debt is classified as Level 2 and is based on observed or quoted market prices for the same or similar issues, or based 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 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, 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	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative instruments	3. Derivative instruments: We use commodity derivatives to manage our exposure to fluctuation 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 statements 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 December 31, 2022 all of the counterparties with transaction amounts outstanding under our derivative programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. We have entered into International Swaps and Derivatives Association agreements with our natural gas derivative counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties’ credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party’s credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. At December 31, 2022 and 2021, the estimated fair values of our natural gas contracts were net assets of $131,804,000 and $63,994,000, respectively. As of December 31, 2022 and 2021, one of our counterparties was required to post credit collateral totaling $30,400,000 and $1,800,000, 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 items within our consolidated balance sheets. The following table reflects the volume activity of our natural gas derivatives as of December 31, 2022 that is expected to settle or mature each year: ​ ​ ​ ​ ​ ​ Natural Gas ​ ​ Swaps Year ​ (MMBTUs) ​ (in millions) 2023 32.1 2024 27.7 2025 23.3 2026 18.2 2027 6.0 Total 107.3 ​ The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ Location ​ Fair Value ​ ​ ​ ​ 2022 ​ 2021 ​ ​ ​ (dollars in thousands) Assets ​ ​ Natural gas swaps Other current assets ​ $ 35,285 ​ $ 23,596 Natural gas swaps Other deferred charges ​ $ 99,725 ​ $ 40,398 Liabilities ​ ​ Natural gas swaps Other current liabilities ​ $ 3,206 ​ $ — ​ The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, 2022, 2021 and 2020. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenues and ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expenses Location ​ ​ 2022 ​ ​ 2021 ​ ​ 2020 ​ ​ (dollars in thousands) Natural gas swaps gains Fuel ​ $ 121,626 ​ $ 31,440 ​ $ 830 Natural gas swaps losses Fuel ​ (6,587) ​ (1,431) ​ (21,179) Total ​ $ 115,039 ​ $ 30,009 ​ $ (20,349) ​ The following table presents the unrealized (gains) and losses on derivative instruments deferred on the consolidated balance sheets at December 31, 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Balance ​ ​ ​ ​ ​ ​ ​ ​ Sheet Location ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ ​ ​ (dollars in thousands) Natural gas swaps Regulatory liability $ 131,804 $ 63,994 Total ​ $ 131,804 ​ $ 63,994 ​

Investments

Investments	12 Months Ended
	Dec. 31, 2022
Schedule of Investments [Abstract]
Investments	4. Investments: Investments in debt and equity securities Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. The following tables summarize debt and equity securities at December 31, 2022 and 2021. ​ ​ ​ Gross Unrealized 2022 Cost Gains Losses Fair Value ​ ​ (dollars in thousands) 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 ​ ​ ​ ​ Gross Unrealized 2021 Cost Gains Losses Fair Value ​ ​ (dollars in thousands) Equity ​ $ 304,305 ​ $ 280,127 ​ $ (4,682) ​ $ 579,750 Debt ​ 774,580 ​ 4,859 ​ (7,001) ​ 772,438 Other ​ 19,102 ​ — ​ (1) ​ 19,101 Total ​ $ 1,097,987 ​ $ 284,986 ​ $ (11,684) ​ $ 1,371,289 ​ The contractual maturities of debt securities, which are included in the estimated fair value table above, at December 31, 2022 and 2021 are as follows: ​ ​ ​ 2022 ​ 2021 ​ Cost Fair Value Cost Fair Value ​ ​ (dollars in thousands) Due within one year ​ $ 367,199 ​ $ 353,180 ​ $ 223,933 ​ $ 222,307 Due after one year through five years ​ 293,523 ​ 275,073 ​ 371,060 ​ 368,574 Due after five years through ten years ​ 66,255 ​ 62,576 ​ 62,679 ​ 62,639 Due after ten years ​ 106,058 ​ 96,209 ​ 116,908 ​ 118,918 Total ​ $ 833,035 ​ $ 787,038 ​ $ 774,580 ​ $ 772,438 ​ The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2022, 2021 and 2020: ​ ​ 2022 2021 2020 ​ ​ (dollars in thousands) Gross realized gains ​ $ 10,029 ​ $ 33,501 ​ $ 36,647 Gross realized losses ​ (31,979) ​ (19,985) ​ (16,868) Proceeds from sales ​ 301,128 ​ 913,600 ​ 756,513 ​ Investment in associated companies Investments in associated companies were as follows at December 31, 2022 and 2021: ​ ​ 2022 2021 ​ ​ (dollars in thousands) National Rural Utilities Cooperative Finance Corporation (CFC) ​ $ 24,081 ​ $ 24,081 CT Parts, LLC ​ 6,574 ​ 7,049 Georgia Transmission Corporation ​ 38,287 ​ 35,696 Georgia System Operations Corporation ​ 7,750 ​ 6,500 Other ​ 2,245 ​ 2,500 Total ​ $ 78,937 ​ $ 75,826 ​ The CFC investments consist of capital term certificates required in connection with our membership in CFC and a voluntary investment in CFC member capital securities. Accordingly, there is no market for these investments and they are valued at cost. The investment in Georgia Transmission represents capital credits valued at cost. The investment in Georgia System Operations represents loan advances. Repayments of these advances are due by December 2028. CT Parts, LLC is an affiliated organization formed by us and Smarr EMC for the purpose of purchasing and maintaining spare parts inventory and for the administration of contracted services for combustion turbine generation facilities. Such investment is recorded at cost. Rocky Mountain transactions In December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to six separate owner trusts for the benefit of three investors, referred to as owner participants, for a term equal to 120% of the estimated useful life of Rocky Mountain. Immediately thereafter, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation, or RMLC, for a term of 30 years In 2012, we terminated five of the six lease transactions prior to the end of their lease terms. The remaining lease in place represented approximately 10% of the original lease transactions. Pursuant to a payment undertaking agreement, we have a guarantee for the annual basic rent payments due under the remaining lease. The fair value amount relating to the guarantee of basic rent payment is immaterial to us principally due to the high credit rating of the payment undertaker, Rabobank Nederland. The basic rental payments remaining through the end of the lease, which expires in 2027, are approximately $19,565,000. At the end of the term of the remaining facility lease, we have the option to cause RMLC to purchase the owner trust’s undivided interest in Rocky Mountain at a fixed purchase option price of approximately $112,000,000. The payment undertaking agreement, along with the equity funding agreement with AIG Matched Funding Corp., would fund approximately $74,000,000 and $37,928,000 of this amount, respectively, and these amounts would be paid to the owner trust over five installments in 2027. If we do not elect to cause RMLC to purchase the owner trust’s undivided interest in Rocky Mountain, Georgia Power has an option to purchase the undivided interest. If neither we nor Georgia Power exercise our purchase option, and we return (through RMLC) the undivided interest in Rocky Mountain to the owner trust, the owner trust has several options it can elect, including: ● causing RMLC and us to renew the related facility lease and facility sublease for up to an additional 16 years and provide collateral satisfactory to the owner trust, ● leasing its undivided interest to a third party under a replacement lease, or ● retaining the undivided interest for its own benefit. Under the first two of these options we must arrange new financing for the outstanding amount of the loan used to finance the owner trust’s upfront rental payment made to us when the lease closed on December 31, 1996. At the end of the lease term, the amount of the outstanding loan is anticipated to be approximately $74,000,000. If new financing cannot be arranged, the owner trust can ultimately cause us to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the loan certificate or cause RMLC to exercise its purchase option or RMLC to renew the facility lease and facility sublease, respectively. The assets of RMLC are not available to pay our creditors.

Income taxes

Income taxes	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Income taxes	5. Income taxes: While we are a not-for-profit membership corporation formed under the laws of the state of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our members for purposes of calculating our taxable income. We annually allocate income and deductions between patronage and non-patronage activities and substantially all of our income is from patronage-sourced activities, resulting in no current period income tax expense or current or deferred income tax liability. Although we believe that treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment was not sustained, we believe that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on our financial condition or results of operations and cash flows. We account for income taxes pursuant to the authoritative guidance for accounting for income taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. The difference between the statutory federal income tax rate on income before income taxes and our effective income tax rate is summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 Statutory federal income tax rate 21.0 % 21.0 % 21.0 % Patronage exclusion (21.0) % (21.0) % (21.0) % Effective income tax rate 0.0 % 0.0 % 0.0 % ​ The components of our net deferred tax assets and liabilities as of December 31, 2022 and 2021 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ 2022 2021 Deferred tax assets ​ ​ Net operating losses ​ $ 115,080 ​ $ — Obligation related to asset retirements ​ 345,879 ​ 331,311 Advance payments ​ 183,833 ​ 175,077 Other regulatory liabilities ​ 18,687 ​ 54,611 Other assets ​ 30,373 ​ 24,838 Deferred tax assets ​ 693,852 ​ 585,837 Less: Valuation allowance ​ — ​ — Net deferred tax assets ​ $ 693,852 ​ $ 585,837 Deferred tax liabilities ​ ​ Fixed assets and intangibles ​ $ (140,095) ​ $ (40,655) Right-of-use assets-finance leases ​ (77,923) ​ (77,923) Other regulatory asset ​ (343,230) ​ (338,291) Other liabilities ​ (15,352) ​ (17,984) Deferred tax liabilities ​ (576,600) ​ (474,853) Net deferred tax assets (liabilities) ​ $ 117,252 ​ $ 110,984 Less: Patronage exclusion ​ (117,252) ​ (110,984) Net deferred taxes ​ $ — ​ $ — ​ As of December 31, 2022, we generated a current year federal net operating loss of $447,086,000 which may be carried forward indefinitely. Due to the tax basis method for allocating patronage dividends, we will utilize this loss to offset any future federal taxable income prior to member allocation per the bylaws. There is no net impact to the deferred tax asset after the patronage exclusion. The authoritative guidance for income taxes addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. We may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. We file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year 2019 and forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2019 and forward. We have no liabilities recorded for uncertain tax positions.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	6. 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 2022 and 2021 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: ● Renew the leases for a period of not less than one year and not more than five years at fair market value, ● Purchase the undivided interest at fair market value, or ● Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through 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 used our 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 ​ 2022 2021 ​ (dollars in thousands) Right-of-use assets - Finance leases ​ ​ Right-of-use assets ​ $ 302,732 ​ $ 302,732 Less: Accumulated provision for depreciation ​ (272,876) ​ (267,606) Total finance lease assets ​ $ 29,856 ​ $ 35,126 ​ ​ ​ ​ ​ ​ ​ Lease liabilities - Finance leases ​ ​ Obligations under finance leases ​ $ 52,937 ​ $ 61,335 Long-term debt and finance leases due within one year ​ 8,398 ​ 7,541 Total finance lease liabilities ​ $ 61,335 ​ $ 68,876 ​ ​ ​ ​ ​ ​ ​ ​ ​ Classification 2022 2021 ​ ​ (dollars in thousands) Right-of-use assets - Operating leases ​ ​ Electric plant in service, net ​ $ 3,326 ​ $ 2,293 Total operating lease assets ​ $ 3,326 ​ $ 2,293 ​ ​ ​ ​ ​ ​ ​ Lease liabilities - Operating leases ​ ​ Capitalization - Other ​ $ 2,256 ​ $ 1,550 Other current liabilities ​ 1,164 ​ 838 Total operating lease liabilities ​ $ 3,420 ​ $ 2,388 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ ​ ​ (dollars in thousands) Lease Cost Classification ​ ​ Finance lease cost: ​ ​ Amortization of leased assets Depreciation and amortization ​ $ 7,542 ​ $ 6,420 Interest on lease liabilities Interest expense ​ $ 7,408 ​ $ 8,177 ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease cost Inventory(1) & production expense ​ $ 995 ​ $ 1,079 Total lease cost ​ $ 15,945 ​ $ 15,676 (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. ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 December 31, 2021 Lease Term and Discount Rate ​ ​ ​ ​ ​ ​ ​ Weighted-average remaining lease term (in years): ​ Finance leases 5.94 6.90 ​ Operating leases 6.44 8.01 ​ ​ ​ ​ ​ ​ ​ Weighted-average discount rate: ​ Finance leases 11.05 % 11.05 % Operating leases 5.52 % 4.73 % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ (dollars in thousands) Other Information: ​ ​ Cash paid for amounts included in the measurement of lease liabilities ​ ​ Operating cash flows from finance leases ​ $ 7,408 ​ $ 8,177 Operating cash flows from operating leases ​ $ 1,009 ​ $ 1,129 Financing cash flows from finance leases ​ $ 7,541 ​ $ 6,772 ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for new operating lease liabilities ​ $ 1,954 ​ $ — ​ Maturity analysis of our finance and operating lease liabilities as of December 31, 2022 is as follows: ​ Year Ending December 31, Finance Leases Operating Leases Total ​ ​ (dollars in thousands) 2023 ​ $ 14,949 ​ $ 1,324 ​ $ 16,273 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 ​ $ 4,105 ​ $ 89,533 Less: imputed interest ​ (24,093) ​ (685) ​ (24,778) Present value of lease liabilities ​ $ 61,335 ​ $ 3,420 ​ $ 64,755 ​ 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 2022 and 2021 was as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 Lease income ​ $ 6,539 ​ $ 6,312 ​

Debt

Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt	7. Debt: Long-term debt consists of first mortgage notes payable to the United States of America acting through the Federal Financing Bank (FFB) and guaranteed by the Rural Utilities Service or the U.S. Department of Energy, first mortgage bonds payable (FMBs) and first mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds (PCRBs). Substantially all of our owned tangible and certain of our intangible assets are pledged under our first mortgage indenture as collateral for the Federal Financing Bank notes, the first mortgage bonds, and the first mortgage notes issued in conjunction with the sale of pollution control revenue bonds. Maturities for long-term debt and finance lease obligations through 2027 are as follows: ​ ​ 2023 2024 2025 2026 2027 ​ ​ (dollars in thousands) FFB ​ $ 312,695 ​ $ 308,892 ​ $ 282,399 ​ $ 262,793 ​ $ 271,623 FMBs ​ 1,010 ​ 63,510 ​ 62,500 ​ 62,500 ​ 62,500 PCRBs ​ — ​ — ​ — ​ — ​ — ​ ​ $ 313,705 ​ $ 372,402 ​ $ 344,899 ​ $ 325,293 ​ $ 334,123 Finance Leases ​ 8,398 ​ 9,351 ​ 10,413 ​ 11,595 ​ 12,912 Total ​ $ 322,103 ​ $ 381,753 ​ $ 355,312 ​ $ 336,888 ​ $ 347,035 ​ The weighted average interest rate on our long-term debt at December 31, 2022 and 2021 was 3.78% and 3.69%, respectively. Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts at December 31, 2022 and December 31, 2021 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ ​ Unamortized Debt ​ ​ Unamortized Debt ​ ​ ​ ​ ​ Issuance Costs ​ ​ ​ ​ Issuance Costs ​ ​ ​ ​ ​ and ​ ​ ​ ​ and ​ ​ Principal ​ Debt Discounts ​ Principal ​ Debt Discounts ​ ​ (dollars in thousands) FFB ​ $ 7,084,148 ​ $ 52,690 ​ $ 6,526,858 ​ $ 55,159 FMBs ​ 4,152,021 ​ 52,480 ​ 3,653,031 ​ 46,985 PCRBs ​ 704,190 ​ 8,972 ​ 735,165 ​ 9,765 ​ ​ $ 11,940,359 ​ $ 114,142 ​ $ 10,915,054 ​ $ 111,909 ​ We use the effective interest rate method to amortize debt issuance costs and debt discounts as well as the straight-line method when the results approximate those of the effective interest rate method. Unamortized debt issuance costs and debt discounts are being amortized to expense over the life of the respective debt issues. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a multi-advance term loan facility (the Facility) under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility are used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII loan guarantee program (Eligible Project Costs). Borrowings under the Original FFB Notes could not exceed $3,057,069,461, of which $335,471,604 was designated for capitalized interest. We have advanced all amounts available under the Original FFB Notes. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original FFB Notes due to the timing of borrowing and lower than expected interest rates. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in late 2017. At December 31, 2022, borrowings under the Additional FFB Note totaled $1,619,679,706. At December 31, 2022, we had borrowed a total of $4,633,028,088, including capitalized interest under the Department of Energy-guaranteed loans. As of December 31, 2022, we have fully advanced under these guaranteed loans. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began on February 20, 2020. As of December 31, 2022, we have repaid $307,600,000 of principal borrowed on the FFB Notes. Interest rates on advances during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. If certain events occur, referred to as an “Alternate Amortization Event,” at the Department of Energy’s option the Federal Financing Bank’s commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or 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 consecutive months, (xii) change of control of Oglethorpe and (xiii) certain events of loss or condemnation. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility. b) Rural Utilities Service Guaranteed Loans: During 2022, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $317,245,000 for long-term financing of general and environmental improvements at existing plants and the Effingham acquisition. This total includes a Rural Utilities Service-guaranteed loan that provided long-term funding for the Effingham acquisition in the amount of In January 2023, we received an additional $15,431,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Credit Facilities: As of December 31, 2022, we had a total of $1,810,000,000 of committed credit arrangements comprised of four separate facilities with maturity dates that range from December 2023 to December 2024. These credit facilities are for general working capital purposes, issuing letters of credit and backing up outstanding commercial paper. Under our unsecured committed lines of credit that we had in place at December 31, 2022, we had the ability to issue letters of credit totaling $960,000,000 in the aggregate, of which $957,000,000 remained available. At December 31, 2022, we had (i) $2,504,000 under these lines of credit in the form of issued letters of credit and (ii) $659,000,000 dedicated under one of these lines of credit to support a like amount of commercial paper that was outstanding. d) First Mortgage Bonds: On April 12, 2022, we issued $500,000,000 of 4.50% first mortgage bonds, Series 2022A, for the purpose of providing long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. In conjunction with the issuance of the bonds, we repaid $493,405,000 of outstanding commercial paper. The bonds are due to mature April 2047 and are secured under our first mortgage indenture. e) Pollution Control Revenue Bonds: On September 9, 2022, we redeemed $30,975,000 of Series 2017 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 indexed put rate modes 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.

Electric plant, construction an

Electric plant, construction and related agreements	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Electric plant, construction and related agreements	8. Electric plant, construction and related agreements: a. Electric plant We, along with Georgia Power, have entered into agreements providing for the purchase and subsequent joint operation of certain electric generating plants. Each co-owner is responsible for providing their own financing. The plant investments disclosed in the table below represent our undivided interest in each plant. A summary of our plant investments and related accumulated depreciation as of December 31, 2022 and 2021 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ ​ Accumulated ​ ​ Accumulated Plant ​ Investment ​ Depreciation ​ Investment ​ Depreciation ​ ​ (dollars in thousands) In-service (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Owned property ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Vogtle Units No. 1 & No. 2 ​ $ 3,024,112 ​ $ (1,916,942) ​ $ 3,010,843 ​ $ (1,881,324) (Nuclear – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Vogtle Units No. 3 & No. 4 ​ 58,189 ​ (8,627) ​ 58,199 ​ (7,290) (Nuclear – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hatch Units No. 1 & No. 2 ​ 991,852 ​ (533,771) ​ 973,682 ​ (503,871) (Nuclear – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Wansley Units No. 1 & No. 2 (2) ​ 20,312 ​ (15,337) ​ 820,110 ​ (649,301) (Fossil – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Scherer Unit No. 1 ​ 1,378,904 ​ (636,799) ​ 1,415,115 ​ (638,443) (Fossil – 60% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Doyle (Combustion Turbine - 100% ownership) ​ 145,780 ​ (124,306) ​ 144,711 ​ (120,527) Rocky Mountain Units No. 1, No. 2 & No. 3 ​ 616,278 ​ (296,624) ​ 615,485 ​ (284,749) (Hydro – 75% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hartwell (Combustion Turbine - 100% ownership) ​ 232,532 ​ (125,092) ​ 227,834 ​ (121,174) Hawk Road (Combustion Turbine - 100% ownership) ​ 269,837 ​ (74,685) ​ 266,149 ​ (69,194) Talbot (Combustion Turbine - 100% ownership) ​ 301,869 ​ (162,137) ​ 300,335 ​ (158,270) Chattahoochee (Combined cycle - 100% ownership) ​ 324,310 ​ (171,272) ​ 319,550 ​ (166,859) Effingham (Combined cycle - 100% ownership) ​ 339,189 ​ (121,318) ​ 337,614 ​ (112,057) Smith (Combined cycle - 100% ownership) ​ 686,517 ​ (208,142) ​ 672,184 ​ (190,760) Wansley (Combustion Turbine – 30% ownership) (2) ​ — ​ — ​ 3,942 ​ (3,889) Washington County (Combustion Turbine – 100% ownership) ​ 170,432 ​ (88,585) ​ — ​ — Transmission plant ​ 107,992 ​ (64,785) ​ 102,966 ​ (62,457) Other ​ 106,424 ​ (65,922) ​ 104,372 ​ (62,885) Property under finance lease: ​ ​ ​ ​ Scherer Unit No. 2 (Fossil – 60% leasehold) ​ 794,830 ​ (569,245) ​ 795,301 ​ (532,674) Total in-service ​ $ 9,569,359 ​ $ (5,183,589) ​ $ 10,168,392 ​ $ (5,565,724) Construction work in progress ​ ​ ​ ​ Vogtle Units No. 3 & No. 4 ​ $ 7,583,291 ​ ​ $ 6,680,014 ​ Environmental and other generation improvements ​ 132,744 ​ ​ 99,378 ​ Total construction work in progress ​ $ 7,716,035 ​ ​ $ 6,779,392 ​ (1) Amounts include plant acquisition adjustments at December 31, 2022 of $280,396,000 and December 31, 2021 of $248,000,000 . (2) Plant Wansley Units No. 1 and No. 2 and the combustion turbine were retired on August 31, 2022. The remaining balance represents land and certain asset retirement obligations. Our proportionate share of direct expenses of joint operation of the above plants is included in the corresponding operating expense captions (e.g., fuel, production) on the accompanying consolidated statements of revenues and expenses. b. Construction Vogtle Units No. 3 and No. 4 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 June 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 $8.65 billion. At December 31, 2022, our total investment for our interest in the additional Vogtle units was approximately $8.0 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation. Our initial ownership interest and proportionate share of the cost to construct the additional Vogtle units was 30%, representing approximately 660 megawatts. However, we have exercised the tender option discussed below which caps our capital costs in exchange for a proportionate reduction of our 30% interest in the two units. Based on the current project budget and schedule and our interpretation of the Global Amendments (described below), we would transfer approximately 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. ​ The table below shows our project budget and actual costs through December 31, 2022 for our share of the project. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Actual Costs at December ​ ​ Project Budget (Tender) ​ 31, 2022 ​ ​ (in millions) Construction Costs (1) ​ $ 6,554 ​ $ 6,147 Freeze Capital Credit (2) ​ ​ (528) ​ ​ — Financing Costs ​ 2,025 ​ 1,770 Subtotal ​ $ 8,051 ​ $ 7,917 Deferred Training Costs ​ 47 ​ 46 Total Project Costs Before Contingency ​ $ 8,098 ​ $ 7,963 ​ ​ ​ ​ ​ ​ ​ Oglethorpe Contingency ​ $ 2 ​ $ — Totals ​ $ 8,100 ​ $ 7,963 (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. ​ 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 June 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $30 million per month for both units and approximately $13 million per month for Unit No. 4. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of 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 December 31, 2022, the incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity, substantially all of which occurred during 2020 and 2021, is estimated by Georgia Power to be between $350 million and $438 million and is included in the project budget. Future COVID-19 variants could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4. On July 29, 2022, Southern Nuclear announced that all Unit No. 3 inspections, tests, analyses, and acceptance criteria documentation had been submitted to the Nuclear Regulatory Commission. On August 3, 2022, the Nuclear Regulatory Commission published its 103(g) finding that the acceptance criteria in the combined license for Unit No. 3 had been met, which allowed for nuclear fuel to be loaded and start-up testing to begin. Fuel load for Unit No. 3 was completed on October 17, 2022. In early 2023, during the start-up and pre-operational testing for Unit No. 3, Southern Nuclear identified and remediated certain equipment and component issues. On March 6, 2023, the Unit No. 3 nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality, a key milestone in the start-up process. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 during May or June of 2023. Our current budget reflects our expectation of an in-service date for Unit No. 3 in June 2023. The projected schedule for Unit No. 3 primarily depends on the progression of final component and pre-operational testing and start-up, which may be impacted by further equipment, component and/or other operational challenges. 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, which commenced on March 20, 2023, and other testing, the pace and quality of remaining commodities installation; completion of documentation to support inspections, tests, analyses and acceptance criteria submittals; the pace of remaining work package closures and system turnovers; and 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 startup, 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, Unit No. 3 is now under the Nuclear Regulatory Commission’s operating reactor oversight process and must meet applicable technical and operational requirements contained within 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 report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs. ● Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and ● Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest). If the EAC is revised and exceeds the EAC in VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, has a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s share of construction costs actually incurred in excess of the EAC in VCM 19 plus $2.1 billion. If any Co-owner elects to exercise this tender option, Georgia Power would have the option to cancel the project in lieu of accepting the offer to purchase a portion of the Co-owner’s ownership interest. If Georgia Power does not elect to cancel the project, then Georgia Power must accept the offer, and the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the percentage of the cumulative amount of construction costs paid by such tendering Co-owner as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of the tendering Co-owner in accordance with the second and third bullets above will be treated as payments made by that Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a proportionate reduction of our 30% ownership interest. The VCM 19 total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. As of December 31, 2021, budget increases since VCM 19 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 approximately 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 approximately $530 million in construction 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 has been triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. We and Georgia Power also do not agree on the dollar amount that triggers Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above is triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in 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 $8.65 billion, and we would incur approximately $530 million of additional construction costs (excluding related financing costs) and, 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 7. The ultimate outcome of these matters cannot be determined at this time.

Employee benefit plans

Employee benefit plans	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Employee benefit plans	9. Employee benefit plans: Our retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of his or her eligible annual compensation. At our discretion, we may match the employee’s contribution and have done so each year of the plan’s existence. The match, which is calculated each pay period, currently can be equal to as much as three-quarters of the first 6% of an employee’s eligible compensation, depending on the amount and timing of the employee’s contribution. Our contributions to the matching feature of the plan were approximately $2,017,000, $1,811,000 and $1,716,000 in 2022, 2021 and 2020, respectively. Our 401(k) plan also includes an employer retirement contribution feature, which subject to IRS limitations, contributes 11% of an employee’s eligible annual compensation. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $5,098,000, $4,527,000 and $4,371,000 in 2022, 2021 and 2020, respectively. We also sponsor two deferred compensation plans for eligible employees. Eligible employees are defined as highly compensated individuals within the definition of the Internal Revenue Code. The plans offer investment options to all eligible participants without regard to salary limits. In addition, one plan enables us to continue employer retirement contributions to highly compensated employees who exceed Internal Revenue Code salary limits for retirement plan contributions. The value of the plans is recorded as an asset and an equal offsetting liability with balances of $4,616,000 and $5,840,000 in 2022 and 2021, respectively.

Nuclear insurance

Nuclear insurance	12 Months Ended
	Dec. 31, 2022
Nuclear insurance:
Nuclear insurance	10. Nuclear insurance: The Price-Anderson Act limits public liability claims that could arise from a single nuclear incident to $13.7 billion. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $450 million, a licensee of a nuclear power plant could be assessed a deferred premium of up to $138 million per incident for each licensed reactor operated by it, but not more than $20 million per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in five nuclear reactors, we could be assessed a maximum of $206 million per incident, but not more than $31 million in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every 5 years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than November 1, 2023. Georgia Power, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to provide property damage insurance coverage in an amount up to $1.5 billion for members’ operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1.25 billion for nuclear losses and policies providing coverage up to $750 million for non-nuclear losses in excess of the $1.5 billion primary coverage. NEIL also covers the additional costs that could be incurred in obtaining replacement power during a prolonged accidental outage at a member’s nuclear plant. Members can purchase this coverage, subject to a deductible waiting period of up to 26 weeks, with a maximum per occurrence per unit limit of $490 million. After the deductible period, weekly indemnity payments would be received until either the unit is operational or until the limit is exhausted. In December 2022, we became members of NEIL which will allow us to participate in this coverage in 2023. Georgia Power, on behalf of all the co-owners has purchased a builders’ risk property insurance policy from NEIL for Vogtle Units No. 3 and No. 4. This policy provides $2.75 billion in limits for accidental property damage occurring during construction. Under each of the NEIL policies, members are subject to retroactive assessments in proportion to their premiums, if losses each year exceed the accumulated reserve funds available to the insurer. The portion of the current maximum annual assessment for Georgia Power that would be payable by Oglethorpe based on ownership share, is limited to approximately $41 million. Claims resulting from terrorist acts and cyber events are covered under both the ANI and NEIL policies (subject to normal policy limits). The maximum aggregate that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3.2 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. The maximum aggregate that NEIL will pay for all claims resulting from cyber acts and cyber events in any 12-month period is $3.2 billion each, plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources. For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are next to be applied toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to Georgia Power, for the benefit of all the co-owners, or to bond trustees as may be appropriate under the policies and applicable trust indentures. All retrospective assessments, whether generated for liability or property, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. Uninsured losses and other expenses could have a material adverse effect on our financial condition and results of operations.

Commitments

Commitments	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Commitments	11. Commitments: We have entered into long-term commitments to meet fuel, transportation, maintenance and asset retirement requirements. To supply a portion of the fuel requirements to our co-owned generating units, Georgia Power, on our behalf for coal and Southern Nuclear on our behalf for nuclear fuel, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does not include taxes, transportation, government impositions or railcar costs. We have entered into long-term agreements with various counterparties to provide firm natural gas transportation to our natural gas-fired facilities. The value of these agreements is based on fixed rates as provided in the contracts and does not include variable costs. We have also entered into long-term maintenance agreements for certain of our natural gas-fired facilities. In most cases, these agreements include provisions for price escalation and performance bonuses and, if applicable, are included in the values; timing of expenditures is based on current operational assumptions. Certain agreements contain significant cancellation for convenience penalties and, therefore, amounts in the table below include total estimated expenditures over the life of the agreement. If these agreements were terminated by us in 2023 for convenience, our cancellation obligation would be approximately $96,796,000. We have asset retirement obligations which are legal obligations to retire long-lived assets. These obligations are primarily for the decommissioning of our nuclear units and coal ash ponds. Expenditures are based on estimates determined through decommissioning studies and include provisions for price escalation and other factors. See Note 1h for information regarding our asset retirement obligations. We have a small portfolio of leases with the most significant being a finance lease for our 60% undivided interest in Scherer Unit No. 2. In addition, we have other operating leases including railcar leases for the transportation of coal at our coal-fired plants and various other leases of minimal value. For information regarding these leases, see Note 6. As of December 31, 2022, our estimated commitments are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Asset ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gas ​ Maintenance ​ Retirement ​ Finance and ​ ​ Coal ​ Nuclear Fuel ​ Transportation ​ Agreements ​ Obligations ​ Operating Leases ​ ​ (dollars in thousands) 2023 ​ $ 26,891 ​ $ 78,780 ​ $ 63,850 ​ $ 29,720 ​ $ 16,709 ​ $ 16,273 2024 ​ 26,070 ​ 39,690 ​ 62,818 ​ 57,749 ​ 52,003 ​ 15,799 2025 ​ 10,426 ​ 32,280 ​ 62,775 ​ 43,025 ​ 46,128 ​ 15,590 2026 ​ — ​ 28,980 ​ 68,872 ​ 15,736 ​ 49,445 ​ 15,299 2027 ​ — ​ 26,580 ​ 67,188 ​ 3,237 ​ 67,384 ​ 15,021 Thereafter ​ — ​ 67,170 ​ 824,627 ​ 316,160 ​ 3,416,582 ​ 11,551 ​

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	12 Months Ended
	Dec. 31, 2022
Contingencies and Regulatory Matters:
Contingencies and Regulatory Matters	12. 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 annual 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 in 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 seven of 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. We and the other co-owners of Plant Scherer filed motions to dismiss Florida Power & Light and JEA’s complaint and, on February 9, 2023, the court granted our motions to dismiss with leave to amend. On March 13, 2023, Florida Power & Light and JEA filed an amended complaint. While we do not believe that the co-ownership agreements support the arguments raised by Florida Power & Light Company and JEA, if their arguments were to be successful in this case, we could be responsible for an increased percentage of these costs relating to our interests in Scherer Unit Nos. 1 and 2. The amount of additional costs relating to these future projects, if any, cannot be determined at this time.

Plant Wansley

Plant Wansley	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Plant Wansley	13. 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. At December 31, 2022, we recognized an additional $40,656,000 in liabilities related to the Wansley coal ash pond asset retirement obligation. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures.

Plant Acquisition

Plant Acquisition	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Plant Acquisition	14. Plant Acquisition: On December 20, 2022, we acquired two generating units at the Washington County Power Plant, a four-unit 660 megawatt combustion turbine generation and transmission facility located in Sandersville, Georgia, from Gulf Pacific Power, LLC, an investment fund managed by Harbert Management Corporation. The two acquired units added over 300 megawatts of natural gas-fired capacity to our generation portfolio. As part of the acquisition of the units we assumed an existing power purchase and sale agreement to sell the capacity and associated energy to Georgia Power through May 31, 2024. On June 1, 2024, the output of the acquired units will be available to our subscribing members. As a result of the power purchase and sale agreement with Georgia Power, our subscribing members are not allowed to take output and we are deferring the current results of operations through the end of the agreement. Residual net results of operations from Washington County, including related interest costs, are being deferred as a regulatory asset. This regulatory asset will be amortized over the then remaining life of the plant, estimated to be 24 years at June 2024. Some of our members elected to take service (scheduling members) at the end of the power purchase and sale agreement with Georgia Power and some members have elected to defer (deferring members) their share of output until on or before January 2026. Residual net results of operations attributable to the deferring members will also be deferred as a regulatory asset and amortized over the then remaining life of the plant. If a deferring member elects to take service before January 2026, amortization of the regulatory asset will begin upon taking service. The purchase price was $86,826,000 and the acquisition also included other transaction costs of approximately $1,051,000 (consisting primarily of legal and professional services). We accounted for the acquisition as an asset acquisition. We financed the acquisition on an interim basis through the issuance of commercial paper. We intend to submit a loan application to the Rural Utilities Service for long-term financing of this acquisition. For any amounts not funded through the Rural Utilities Service, we intend to issue first mortgage bonds. We expect that any financing from the Rural Utilities Service or through first mortgage bonds will be secured under our first mortgage indenture. The following amounts represent the identifiable assets acquired and liabilities assumed in the Washington County acquisition: ​ ​ ​ ​ ​ Classification ​ ​ ​ (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: ​ Electric plant in service, net ​ $ 80,878 Inventories, at average cost ​ 981 Other current assets ​ 417 Power purchase and sale agreement ​ 4,708 Other current liabilities ​ (158) Total identifiable net assets ​ $ 86,826 ​

Quarterly financial data (unaud

Quarterly financial data (unaudited)	12 Months Ended
	Dec. 31, 2022
Quarterly Financial Data [Abstract]
Quarterly financial data (unaudited)	15. Quarterly financial data (unaudited): Summarized quarterly financial information for 2022 and 2021 is as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ Quarter ​ Quarter ​ Quarter ​ Quarter ​ (dollars in thousands) 2022 ​ ​ ​ ​ Operating revenues ​ $ 420,442 ​ $ 533,128 ​ $ 704,265 ​ $ 472,302 Operating margin ​ 57,845 ​ 54,269 ​ 64,553 ​ 17,384 Net margin ​ 21,980 ​ 18,167 ​ 32,097 ​ (10,540) 2021 ​ ​ ​ ​ Operating revenues ​ $ 376,331 ​ $ 358,127 ​ $ 460,822 ​ $ 409,583 Operating margin ​ 64,573 ​ 53,035 ​ 46,025 ​ 30,748 Net margin ​ 25,958 ​ 13,145 ​ 8,907 ​ 9,771 ​

Summary of significant accoun_2

Summary of significant accounting policies (Policies)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Business description	a. Business description Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,744 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 733 megawatts of summer planning reserve capacity. In addition, we supply financial and management services to Green Power EMC, which purchases energy from renewable energy facilities totaling 584 megawatts of capacity, including 552 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.4 million people.
Basis of accounting	b. Basis of accounting Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiary. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation. Certain prior year amounts have been reclassified to conform with current year presentation. We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2022 and 2021 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2022. Examples of estimates used include items related to our asset retirement obligations. Accounting for asset retirement and environmental obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Estimating the amount and timing of future expenditures includes, among other things, making projections of when assets will be retired and ultimately decommissioned, the amount of decommissioning costs, and how costs will escalate with inflation. Actual results could differ from those estimates.
Patronage capital and membership fees	c. Patronage capital and membership fees We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenues over expenditures from operations is treated as an advance of capital by our members and is allocated to each member on the basis of their fixed percentage capacity cost responsibilities in our generation resources. Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities.
Margin policy	d. Margin policy 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 the years 2022, 2021 and 2020, we achieved a margins for interest ratio of 1.14.
Revenue recognition and Deferred credits and other liabilities	e. 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 sell energy and capacity to non-members through industry standard contracts and negotiated agreements, respectively. 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 its 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 December 31, 2022, we did not have any significant long-term contracts with non-members. The consideration we receive for providing capacity services to our members 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 1q. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our member capacity revenues are based on the associated costs we expect to recover in a given year and are 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 1p. 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. In 2022, 2021 and 2020, we provided approximately 58%, 62% 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 2022, 2021 and 2020, our board approved, and we achieved, a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of December 31, 2022 and December 31, 2021, we recognized refund liabilities totaling $28,471,000 and $30,029,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ 2020 ​ ​ (dollars in thousands) Capacity revenues ​ $ 984,036 ​ $ 946,662 ​ $ 971,071 Energy revenues ​ 990,647 ​ 610,447 ​ 405,939 Total ​ $ 1,974,683 ​ $ 1,557,109 ​ $ 1,377,010 ​ The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2022, 2021 or 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 Jackson EMC 16.0 % 15.2 % 15.2 % GreyStone Power Corporation, an EMC 10.0 % 8.7 % 8.7 % Cobb EMC 9.5 % 12.3 % 13.2 % ​ Receivables from contracts with our members at December 31, 2022 and December 31, 2021 were $187,401,000 and $143,715,000, respectively. Energy revenues from non-members were primarily due from the sale of the Effingham deferring members’ output into the wholesale market. In 2022, we recognized capacity revenues from non-members relating to our Washington County acquisition. For additional information regarding the Washington County acquisition, see Note 14. Sales to non-members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 ​ ​ (dollars in thousands) Energy revenues ​ $ 155,372 ​ $ 47,754 ​ $ 608 Capacity revenues ​ 82 ​ — ​ — Total ​ $ 155,454 ​ $ 47,754 ​ $ 608 ​ 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 in 2022, 2021 and 2020 were $14,796,000, $15,693,000 and $14,684,000, respectively. The cumulative amount billed since inception of the program totaled $126,432,000. In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. During the first quarter of 2022, we began applying billing credits to some of our participating members within this program. Under this program, amounts billed to participating members, net of credits, during 2022, 2021 and 2020 were $11,774,000, $143,000,000 and $125,842,000 respectively. Funds collected through this program are invested and held until applied to members’ bills. Investments that mature and are expected to be applied to members’ bills within the next twelve months are included in the Short-term investments line item within our consolidated balance sheets. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members’ bills. The net cumulative amount billed since inception of the program totaled $369,102,000. p. Deferred credits and other liabilities 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 monthly 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 2023. Deferred credits and other liabilities also consists of asset retirement obligations as discussed in Note 1h and regulatory liabilities in Note 1q.
Receivables	f. Receivables A substantial portion of our receivables are related to capacity and energy sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs, plus a margin requirement. Receivables from contracts with our members at December 31, 2022, 2021 and 2020 were $187,401,000, $143,715,000 and $135,462,000, respectively. Payment is typically received the following month in which capacity and energy are billed. Estimated energy charges are billed based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. The remainder of our receivables is primarily related to transactions with non-members from the sale of the Effingham deferring members’ output, affiliated companies and investment income. Our receivables from non-members were $32,614,000 at December 31, 2022. Our receivables from non-members were insignificant at December 31, 2021. As a result of our historical experience, the short duration lifetime of our receivables and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of our receivables is remote. During 2022, 2021 and 2020, no credit losses were recognized on any receivables that arose from contracts with members or non-members.
Nuclear fuel cost	g. Nuclear fuel cost The cost of nuclear fuel is amortized to fuel expense based on usage. The total nuclear fuel expense for 2022, 2021 and 2020 amounted to $73,871,000, $77,366,000, and $75,968,000, respectively. Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. Georgia Power filed claims against the U.S. government in 2014 (as amended) seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2011 through December 31, 2014. On June 12, 2019, the U.S. Court of Federal Claims granted Georgia Power’s motion for summary judgement on damages not disputed by the U.S. Government and awarded the undisputed damages to Georgia Power. However, these undisputed damages are not collectable by Georgia Power and no amounts will be recognized in our financial statements until the court enters final judgement on the remaining damages. Georgia Power filed additional claims against the U.S. government in 2017 seeking damages for spent nuclear fuel storage costs at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 covering the period from January 1, 2015 through December 31, 2017. On August 13, 2020, Georgia Power filed amended complaints in each of the lawsuits against the U.S. government in the Court of Federal Claims for damages from January 1, 2018 to December 31, 2019. Our share of the claims outstanding for the period January 1, 2011 through December 31, 2019 are approximately $84,000,000. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the consolidated financial statements as of December 31, 2022 or December 31, 2021 for these claims. The final outcome of these matters cannot be determined at this time. Both Plants Hatch and Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.
Asset retirement obligations and other retirement costs	h. Asset retirement obligations and other retirement costs Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset’s future retirement discounted using a credit-adjusted risk-free rate, and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities and coal ash ponds. In addition, we have retirement obligations related to gypsum cells, powder activated carbon cells, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes. Periodically, we obtain revised cost studies associated with our nuclear and fossil plants’ asset retirement obligations. Actual retirement costs may vary from these estimates. The estimated costs of nuclear and coal ash pond decommissioning are based on the most recent studies performed in 2021 and 2022, respectively. The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Coal Ash Pond Other Total ​ ​ (dollars in thousands) Balance at December 31, 2021 ​ $ 778,214 ​ $ 442,686 ​ $ 66,243 ​ 1,287,143 Liabilities settled ​ — ​ (10,134) ​ (184) ​ (10,318) Accretion ​ 41,892 ​ 12,196 ​ 1,865 ​ 55,953 Deferred accretion ​ — ​ 479 ​ — ​ 479 Change in cash flow estimates ​ — ​ 16,301 ​ (5,815) ​ 10,486 Balance at December 31, 2022 ​ $ 820,106 ​ $ 461,528 ​ $ 62,109 ​ $ 1,343,743 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Coal Ash Pond Other Total ​ ​ (dollars in thousands) Balance at December 31, 2020 ​ $ 738,217 ​ $ 346,589 ​ $ 51,177 ​ $ 1,135,983 Liabilities settled ​ — ​ (17,046) ​ 4,642 ​ (12,404) Accretion ​ 43,206 ​ 11,157 ​ 1,723 ​ 56,086 Deferred accretion ​ — ​ (199) ​ — ​ (199) Change in cash flow estimates ​ (3,209) ​ 102,185 ​ 8,701 ​ 107,677 Balance at December 31, 2021 ​ $ 778,214 ​ $ 442,686 ​ $ 66,243 ​ $ 1,287,143 ​ Asset Retirement Obligations Nuclear Decommissioning. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hatch Hatch Vogtle Vogtle 2021 site study ​ Unit No. 1 ​ Unit No. 2 ​ Unit No. 1 ​ Unit No. 2 Expected start date of decommissioning 2034 2038 2047 2049 ​ ​ (dollars in thousands) Estimated costs based on site study in 2021 dollars: ​ ​ ​ ​ Radiated structures ​ $ 227,000 ​ $ 236,000 ​ $ 200,000 ​ $ 213,000 Spent fuel management ​ 60,000 ​ 51,000 ​ 58,000 ​ 53,000 Non-radiated structures ​ 15,000 ​ 21,000 ​ 24,000 ​ 31,000 Total estimated site study costs ​ $ 302,000 ​ $ 308,000 ​ $ 282,000 ​ $ 297,000 ​ We have established funds to comply with the Nuclear Regulatory Commission regulations regarding the decommissioning of our nuclear plants. See Note 1i for information regarding the nuclear decommissioning funds. We apply the provision of regulated operations to nuclear decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) of our nuclear decommissioning funds are compared to the associated decommissioning expenses with the difference deferred as regulatory asset or liability. As this difference is largely attributable to the timing of decommissioning fund earnings, the difference is recorded as an adjustment to investment income in our consolidated statements of revenues and expenses. Unrealized gains and losses of the decommissioning funds are recorded directly to the regulatory asset or liability for asset retirement obligations in accordance with our ratemaking treatment. Coal Combustion Residuals. We have internally segregated the funds collected for coal ash pond and other CCR decommissioning costs, including earnings thereon. As of December 31, 2022 and December 31, 2021, the fund balances were $153,208,000 and $140,474,000, respectively. We apply the provision of regulated operations to coal ash pond and other CCR decommissioning transactions such that collections and investment income (interest, dividends and realized gains and losses) are compared to the associated decommissioning expenses with the difference deferred to or amortized from the regulatory asset. This difference is recorded to the associated expenses in our consolidated statements of revenues and expenses. Unrealized gains and losses of the associated decommissioning fund are recorded directly to the regulatory asset in accordance with our ratemaking treatment. Other Retirement Costs Accounting standards for asset retirement and environmental obligations do not apply to a retirement cost for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1q.
Nuclear decommissioning funds	i. Nuclear decommissioning funds The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. The NRC definition of decommissioning does not include all costs that may be associated with decommissioning, such as spent fuel management and non-radiated structures. We have established external trust funds to comply with the NRC’s regulations. Upon approval by the NRC, any funding in the external trust in excess of their requirements may be used for other decommissioning costs. In 2022, additional amounts totaling $2,643,000 were contributed to the external trust funds. In 2021, no additional amounts were contributed to the external trust funds. These funds are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. We record the investment securities held in the nuclear decommissioning trust fund at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control. In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds are available to be utilized to fund the external trust funds, should additional funding be required, as well as other decommissioning costs outside the scope of the NRC funding regulations. The funds are included in long-term investments on our consolidated balance sheets. In 2022 we contributed $8,350,000 into the internal funds and in 2021 we contributed $9,750,000 into the internal funds. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2022 and December 31, 2021. The funds were invested in a diversified mix of approximately 69% equity and 31% fixed income securities in 2022 and 71% equity and 29% fixed income securities in 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 External Trust Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2021 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2022 ​ ​ (dollars in thousands) Equity ​ $ 223,336 ​ $ 9,255 ​ $ (3,655) ​ $ 131,572 ​ $ 360,508 Debt ​ 204,935 ​ 191,958 ​ (203,907) ​ (12,869) ​ 180,117 Other ​ (795) ​ 3,287 ​ (2,401) ​ — ​ 91 ​ ​ $ 427,476 ​ $ 204,500 ​ $ (209,963) ​ $ 118,703 ​ $ 540,716 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $ 5,463,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 Internal Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2021 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2022 ​ ​ (dollars in thousands) Equity ​ $ 68,914 ​ $ — ​ $ 10,005 ​ $ 18,995 ​ $ 97,914 Debt ​ 46,856 ​ 76,207 ​ (79,828) ​ (2,741) ​ 40,494 ​ ​ $ 115,770 ​ $ 76,207 ​ $ (69,823) ​ $ 16,254 ​ $ 138,408 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $ 6,384,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 External Trust Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2020 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2021 ​ ​ (dollars in thousands) Equity ​ $ 212,387 ​ $ 50,309 ​ $ (39,360) ​ $ 230,710 ​ $ 454,046 Debt ​ 196,810 ​ 583,003 ​ (574,878) ​ 1,724 ​ 206,659 Other ​ 17 ​ 41,841 ​ (42,653) ​ — ​ (795) ​ ​ $ 409,214 ​ $ 675,153 ​ $ (656,891) ​ $ 232,434 ​ $ 659,910 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $ 18,261,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 Internal Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2020 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2021 ​ ​ (dollars in thousands) Equity ​ $ 50,647 ​ $ — ​ $ 18,267 ​ $ 44,735 ​ $ 113,649 Debt ​ 50,467 ​ 204,150 ​ (207,761) ​ 181 ​ 47,037 ​ ​ $ 101,114 ​ $ 204,150 ​ $ (189,494) ​ $ 44,916 ​ $ 160,686 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $ 14,656,000 . Realized and unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. The nuclear decommissioning trust fund has produced an average annualized return of approximately 5.9% in the last ten years and 5.8% since inception in 1990. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings of our decommissioning fund assets to be sufficient to meet all of our future nuclear decommissioning costs. Notwithstanding the above assumption, our management believes that increases in cost estimates of decommissioning can be recovered in future rates.
Depreciation	j. Depreciation Depreciation is computed on additions when they are placed in service using the composite straight-line method. We use prescribed depreciation rates as well as site specific rates determined through depreciation studies as approved by the Rural Utilities Service. The depreciation rates for steam, nuclear and other production in the table below reflect revised rates from depreciation rate studies completed in 2020 or 2021. Site specific depreciation studies are performed every five years. Annual weighted average depreciation rates in effect in 2022, 2021, and 2020 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Remaining Useful ​ ​ ​ ​ ​ Life Range in ​ ​ ​ ​ ​ ​ ​ ​ years* ​ 2022 ​ 2021 ​ 2020 Steam production 20-22 13.77 % 14.47 % 2.58 % Nuclear production 12-27 2.17 % 2.18 % 1.93 % Hydro production 44 2.00 % 2.00 % 2.00 % Other production 17-26 2.68 % 2.60 % 2.61 % Transmission 12-27 2.75 % 2.75 % 2.75 % General 1-43 2.00 - 33.33 % 2.00-33.33 % 2.00-33.33 % * Based on estimated retirement dates as of 2022. Actual retirement dates may be different. Remaining useful lives for nuclear production are based on the expiration date of the applicable operating license approved by the NRC. Depreciation expense for the years 2022, 2021 and 2020 was $278,452,000, $269,280,000, and $242,822,000, respectively. In 2021, the composite depreciation rate for Plant Wansley was increased in anticipation of the plant’s retirement in 2022. In addition to the depreciation expense recognized in 2022 and 2021, $165,013,000
Electric plant	k. Electric plant Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, including acquisition adjustments, if any, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years 2022, 2021 and 2020, the allowance for funds used during construction rates were 4.03%, 3.90% and 4.00%, respectively. Replacements and renewals of items considered to be units of property, the lowest level of property for which we capitalize, are charged to the plant accounts. At the time properties are disposed of, the original cost is charged to the accumulated provision for depreciation. Cost of removal, less salvage, is charged to a regulatory liability, accumulated retirement costs for other assets. Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense, including certain major maintenance costs at our natural gas-fired plants.
Cash and cash equivalents	l. Cash and cash equivalents We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments.
Restricted cash and investments	m. Restricted cash and investments Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. For the period from January 1, 2021 to September 30, 2021, deposits earned interest at 4% per annum. Beginning October 1, 2021, the rate was set at the 1-year floating treasury rate, which was 0.09% per annum, and will be reset annually on October 1 of each year thereafter. On October 1, 2022, the rate was reset at the 1-year floating treasury rate, which was 4.05% per annum. The program no longer allows additional funds to be deposited into the account. At December 31, 2022 and 2021, we had restricted investments totaling $74,031,000 and $320,052,000, respectively, of which $74,031,000 and $246,350,000, respectively, were classified as current. Restricted cash consists of collateral posted by our counterparties under our natural gas swap agreements. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the consolidated balance sheets that sum to the total of the same such amounts reported in the consolidated statements of cash flows. ​ Classification ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Twelve months ended ​ December 31, December 31, ​ 2022 2021 ​ (dollars in thousands) Cash and cash equivalents ​ $ 595,381 ​ $ 579,350 Restricted cash included in restricted cash and short-term investments ​ 30,400 ​ 1,800 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows ​ $ 625,781 ​ $ 581,150 ​
Inventories	n. Inventories We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost. The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed. At December 31, 2022 and December 31, 2021, fossil fuels inventories were $64,386,000 and $44,601,000, respectively. Inventories for spare parts at 2022 and 2021 were $233,565,000 and $215,925,000, respectively.
Deferred charges and other assets	o. Deferred charges and other assets Other deferred charges primarily represent advance deposits to Georgia Power Company related to the Vogtle construction project and future generation project costs. For a discussion regarding regulatory assets, see Note 1q.
Regulatory assets and liabilities	q. Regulatory assets and liabilities We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates established under the wholesale power contracts we have with each of our members. These 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 members. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ 2022 2021 Regulatory Assets: ​ ​ ​ ​ ​ ​ Premium and loss on reacquired debt (a) ​ $ 29,494 ​ $ 33,200 Amortization on financing leases (b) ​ 31,908 ​ 34,179 Outage costs (c) ​ 29,317 ​ 31,956 Asset retirement obligations – Ashpond and other (l) ​ 353,212 ​ 335,231 Asset retirement obligations – Nuclear (l) ​ 32,192 ​ — Depreciation expense - Plant Vogtle (d) ​ 35,549 ​ 36,973 Depreciation expense - Plant Wansley (e) ​ 361,784 ​ 204,891 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (f) ​ 54,701 ​ 55,857 Interest rate options cost (g) ​ 136,827 ​ 131,556 Deferral of effects on net margin – Smith Energy Facility (h) ​ 136,730 ​ 142,675 Other regulatory assets (o) ​ 10,591 ​ 2,272 Total Regulatory Assets ​ $ 1,212,305 ​ $ 1,008,790 Regulatory Liabilities: ​ ​ Accumulated retirement costs for other obligations (i) ​ $ 35,580 ​ $ 22,197 Deferral of effects on net margin – Hawk Road Energy Facility (h) ​ 16,636 ​ 17,253 Deferral of effects on net margin – Effingham Energy Facility (p) ​ 14,825 ​ — Major maintenance reserve (j) ​ 74,584 ​ 73,059 Amortization on financing leases (b) ​ 5,557 ​ 8,457 Deferred debt service adder (k) ​ 154,514 ​ 138,897 Asset retirement obligations – Nuclear (l) ​ — ​ 164,256 Revenue deferral plan (m) ​ 357,460 ​ 359,799 Natural gas hedges (n) ​ 131,804 ​ 63,994 Other regulatory liabilities (o) ​ 1,230 ​ 1,537 Total Regulatory Liabilities ​ $ 792,190 ​ $ 849,449 Net regulatory assets ​ $ 420,115 ​ $ 159,341 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 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 allows for additional collections over a five-year period beginning in 2018. These amounts will be amortized to income and applied to member billings, per each member’s 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.
Related parties	r. Related parties We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members’ power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our owned facilities. For 2022, 2021, and 2020, we incurred expenses from Georgia Transmission of $40,774,000, $39,677,000 and $37,931,000, respectively. We, Georgia Transmission and 38 of our members are members of Georgia System Operations. Georgia System Operations operates the system control center and currently provides us system operations services and administrative support services. For 2022, 2021, and 2020, we incurred expenses from Georgia System Operations of $27,416,000, $26,936,000, and $27,104,000, respectively.
Other income	s. Other income Other income includes net revenue from Georgia Transmission and Georgia System Operations for administrative costs, as well as capital credits from investments in associated organizations and other miscellaneous income. In 2021, other income increased due to the recognition of gains on the sale of spare inventory parts from one of our generating facilities.
Recently issued or adopted accounting pronouncements	t. Recently issued or adopted accounting pronouncements In March 2020, the Financial Accounting Standards Board (FASB) issued “Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” The amendments in this update apply to all entities that have contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this update provide optional expedients and exceptions for applying U.S. GAAP to transactions affected by reference rate reform if certain criteria are met. The expedients and exceptions provided by the amendments in this update do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity has elected certain optional expedients that are retained through the end of the hedging relationship. In January 2021, the FASB issued “Reference Rate Reform (Topic 848): Scope,” to further clarify the scope of the reference rate reform guidance in Topic 848. The amendments in this update refine the scope of Topic 848 to clarify that certain optional expedients and exceptions therein for contract modifications and hedge accounting apply to contracts that are affected by the discounting transition. Specifically, modifications related to reference rate reform would not be considered an event that requires reassessment of previous accounting conclusions. The amendments in this update also amend the expedients and exceptions in Topic 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments in these updates were effective for all entities as of March 12, 2020 through December 31, 2022. In December 2022, the FASB issued “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848.”, that defers the sunset date of Topic 848 from December 31, 2022 to December 31, 2024, after which entities will no longer be permitted to apply the relief in Topic 848. We have fully completed our evaluation of this new standard. The adoption of this standard on January 1, 2022 did not have a material impact on our consolidated financial statements.
Measurement of credit losses on financial instruments	u. Measurement of credit losses on financial instruments The financial assets we hold that are subject to credit losses (Topic 326) are predominately accounts receivable and certain cash equivalents classified as held-to-maturity debt (e.g. commercial paper). Our receivables are generally due within thirty days or less with a significant portion related to billings to our members. See Note 1f for information regarding our member receivables. Commercial paper issuances we invest in are rated as investment grade and backed by a credit facility. Given our historical experience, the short duration lifetime of these financial assets and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of these financial assets is remote and we have not recognized an allowance for credit losses.

Summary of significant accoun_3

Summary of significant accounting policies (Tables)	12 Months Ended
	Dec. 31, 2022
Accounting Policies [Abstract]
Schedule of sales to members	Sales to members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ 2020 ​ ​ (dollars in thousands) Capacity revenues ​ $ 984,036 ​ $ 946,662 ​ $ 971,071 Energy revenues ​ 990,647 ​ 610,447 ​ 405,939 Total ​ $ 1,974,683 ​ $ 1,557,109 ​ $ 1,377,010 ​ Sales to non-members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 ​ ​ (dollars in thousands) Energy revenues ​ $ 155,372 ​ $ 47,754 ​ $ 608 Capacity revenues ​ 82 ​ — ​ — Total ​ $ 155,454 ​ $ 47,754 ​ $ 608 ​
Schedule of members whose revenues accounted for 10% or more of total operating revenues	The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2022, 2021 or 2020: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 Jackson EMC 16.0 % 15.2 % 15.2 % GreyStone Power Corporation, an EMC 10.0 % 8.7 % 8.7 % Cobb EMC 9.5 % 12.3 % 13.2 % ​
Schedule of sales to non-members	Sales to members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ 2020 ​ ​ (dollars in thousands) Capacity revenues ​ $ 984,036 ​ $ 946,662 ​ $ 971,071 Energy revenues ​ 990,647 ​ 610,447 ​ 405,939 Total ​ $ 1,974,683 ​ $ 1,557,109 ​ $ 1,377,010 ​ Sales to non-members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 ​ ​ (dollars in thousands) Energy revenues ​ $ 155,372 ​ $ 47,754 ​ $ 608 Capacity revenues ​ 82 ​ — ​ — Total ​ $ 155,454 ​ $ 47,754 ​ $ 608 ​
Schedule reflecting details of asset retirement obligations included in the consolidated balance sheets	The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Coal Ash Pond Other Total ​ ​ (dollars in thousands) Balance at December 31, 2021 ​ $ 778,214 ​ $ 442,686 ​ $ 66,243 ​ 1,287,143 Liabilities settled ​ — ​ (10,134) ​ (184) ​ (10,318) Accretion ​ 41,892 ​ 12,196 ​ 1,865 ​ 55,953 Deferred accretion ​ — ​ 479 ​ — ​ 479 Change in cash flow estimates ​ — ​ 16,301 ​ (5,815) ​ 10,486 Balance at December 31, 2022 ​ $ 820,106 ​ $ 461,528 ​ $ 62,109 ​ $ 1,343,743 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Nuclear Coal Ash Pond Other Total ​ ​ (dollars in thousands) Balance at December 31, 2020 ​ $ 738,217 ​ $ 346,589 ​ $ 51,177 ​ $ 1,135,983 Liabilities settled ​ — ​ (17,046) ​ 4,642 ​ (12,404) Accretion ​ 43,206 ​ 11,157 ​ 1,723 ​ 56,086 Deferred accretion ​ — ​ (199) ​ — ​ (199) Change in cash flow estimates ​ (3,209) ​ 102,185 ​ 8,701 ​ 107,677 Balance at December 31, 2021 ​ $ 778,214 ​ $ 442,686 ​ $ 66,243 ​ $ 1,287,143 ​
Schedule of estimated costs of decommissioning of co-owned nuclear facilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hatch Hatch Vogtle Vogtle 2021 site study ​ Unit No. 1 ​ Unit No. 2 ​ Unit No. 1 ​ Unit No. 2 Expected start date of decommissioning 2034 2038 2047 2049 ​ ​ (dollars in thousands) Estimated costs based on site study in 2021 dollars: ​ ​ ​ ​ Radiated structures ​ $ 227,000 ​ $ 236,000 ​ $ 200,000 ​ $ 213,000 Spent fuel management ​ 60,000 ​ 51,000 ​ 58,000 ​ 53,000 Non-radiated structures ​ 15,000 ​ 21,000 ​ 24,000 ​ 31,000 Total estimated site study costs ​ $ 302,000 ​ $ 308,000 ​ $ 282,000 ​ $ 297,000
Schedule of external and internal trust funds by type of investment	The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2022 and December 31, 2021. The funds were invested in a diversified mix of approximately 69% equity and 31% fixed income securities in 2022 and 71% equity and 29% fixed income securities in 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 External Trust Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2021 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2022 ​ ​ (dollars in thousands) Equity ​ $ 223,336 ​ $ 9,255 ​ $ (3,655) ​ $ 131,572 ​ $ 360,508 Debt ​ 204,935 ​ 191,958 ​ (203,907) ​ (12,869) ​ 180,117 Other ​ (795) ​ 3,287 ​ (2,401) ​ — ​ 91 ​ ​ $ 427,476 ​ $ 204,500 ​ $ (209,963) ​ $ 118,703 ​ $ 540,716 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $ 5,463,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 Internal Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2021 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2022 ​ ​ (dollars in thousands) Equity ​ $ 68,914 ​ $ — ​ $ 10,005 ​ $ 18,995 ​ $ 97,914 Debt ​ 46,856 ​ 76,207 ​ (79,828) ​ (2,741) ​ 40,494 ​ ​ $ 115,770 ​ $ 76,207 ​ $ (69,823) ​ $ 16,254 ​ $ 138,408 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $ 6,384,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 External Trust Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2020 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2021 ​ ​ (dollars in thousands) Equity ​ $ 212,387 ​ $ 50,309 ​ $ (39,360) ​ $ 230,710 ​ $ 454,046 Debt ​ 196,810 ​ 583,003 ​ (574,878) ​ 1,724 ​ 206,659 Other ​ 17 ​ 41,841 ​ (42,653) ​ — ​ (795) ​ ​ $ 409,214 ​ $ 675,153 ​ $ (656,891) ​ $ 232,434 ​ $ 659,910 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends and fees of $ 18,261,000 . ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2021 Internal Funds: Cost ​ ​ Net Unrealized Fair Value ​ ​ 12/31/2020 ​ Purchases ​ Proceeds (1) ​ Gain(Loss) ​ 12/31/2021 ​ ​ (dollars in thousands) Equity ​ $ 50,647 ​ $ — ​ $ 18,267 ​ $ 44,735 ​ $ 113,649 Debt ​ 50,467 ​ 204,150 ​ (207,761) ​ 181 ​ 47,037 ​ ​ $ 101,114 ​ $ 204,150 ​ $ (189,494) ​ $ 44,916 ​ $ 160,686 (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $ 14,656,000 .
Schedule of annual depreciation rates	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Remaining Useful ​ ​ ​ ​ ​ Life Range in ​ ​ ​ ​ ​ ​ ​ ​ years* ​ 2022 ​ 2021 ​ 2020 Steam production 20-22 13.77 % 14.47 % 2.58 % Nuclear production 12-27 2.17 % 2.18 % 1.93 % Hydro production 44 2.00 % 2.00 % 2.00 % Other production 17-26 2.68 % 2.60 % 2.61 % Transmission 12-27 2.75 % 2.75 % 2.75 % General 1-43 2.00 - 33.33 % 2.00-33.33 % 2.00-33.33 % * Based on estimated retirement dates as of 2022. Actual retirement dates may be different. Remaining useful lives for nuclear production are based on the expiration date of the applicable operating license approved by the NRC.
Reconciliation of cash, cash equivalents and restricted cash	​ Classification ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Twelve months ended ​ December 31, December 31, ​ 2022 2021 ​ (dollars in thousands) Cash and cash equivalents ​ $ 595,381 ​ $ 579,350 Restricted cash included in restricted cash and short-term investments ​ 30,400 ​ 1,800 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows ​ $ 625,781 ​ $ 581,150
Schedule of regulatory assets and liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ 2022 2021 Regulatory Assets: ​ ​ ​ ​ ​ ​ Premium and loss on reacquired debt (a) ​ $ 29,494 ​ $ 33,200 Amortization on financing leases (b) ​ 31,908 ​ 34,179 Outage costs (c) ​ 29,317 ​ 31,956 Asset retirement obligations – Ashpond and other (l) ​ 353,212 ​ 335,231 Asset retirement obligations – Nuclear (l) ​ 32,192 ​ — Depreciation expense - Plant Vogtle (d) ​ 35,549 ​ 36,973 Depreciation expense - Plant Wansley (e) ​ 361,784 ​ 204,891 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (f) ​ 54,701 ​ 55,857 Interest rate options cost (g) ​ 136,827 ​ 131,556 Deferral of effects on net margin – Smith Energy Facility (h) ​ 136,730 ​ 142,675 Other regulatory assets (o) ​ 10,591 ​ 2,272 Total Regulatory Assets ​ $ 1,212,305 ​ $ 1,008,790 Regulatory Liabilities: ​ ​ Accumulated retirement costs for other obligations (i) ​ $ 35,580 ​ $ 22,197 Deferral of effects on net margin – Hawk Road Energy Facility (h) ​ 16,636 ​ 17,253 Deferral of effects on net margin – Effingham Energy Facility (p) ​ 14,825 ​ — Major maintenance reserve (j) ​ 74,584 ​ 73,059 Amortization on financing leases (b) ​ 5,557 ​ 8,457 Deferred debt service adder (k) ​ 154,514 ​ 138,897 Asset retirement obligations – Nuclear (l) ​ — ​ 164,256 Revenue deferral plan (m) ​ 357,460 ​ 359,799 Natural gas hedges (n) ​ 131,804 ​ 63,994 Other regulatory liabilities (o) ​ 1,230 ​ 1,537 Total Regulatory Liabilities ​ $ 792,190 ​ $ 849,449 Net regulatory assets ​ $ 420,115 ​ $ 159,341 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 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 allows for additional collections over a five-year period beginning in 2018. These amounts will be amortized to income and applied to member billings, per each member’s 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.

Fair Value (Tables)

Fair Value (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of assets and liabilities measured at fair value on a recurring basis	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using ​ ​ ​ Quoted Prices in ​ ​ ​ ​ ​ ​ ​ ​ ​ Active Markets for ​ Significant Other ​ Significant ​ ​ December 31, ​ Identical Assets ​ Observable Inputs ​ Unobservable Inputs ​ ​ 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 ​ — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using ​ ​ ​ Quoted Prices in Significant Other Significant ​ ​ ​ ​ ​ Active Markets for ​ Observable ​ Unobservable ​ ​ December 31, ​ Identical Assets ​ Inputs ​ Inputs ​ ​ 2021 ​ (Level 1) ​ (Level 2) ​ (Level 3) ​ (dollars in thousands) Nuclear decommissioning trust funds: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Domestic equity ​ $ 249,999 ​ $ 249,999 ​ $ — ​ $ — International equity trust ​ $ 140,718 ​ — ​ 140,718 ​ — Corporate bonds and debt ​ $ 72,936 ​ — ​ 72,369 ​ 567 US Treasury securities ​ $ 53,321 ​ 53,321 ​ — ​ — Mortgage backed securities ​ $ 40,460 ​ — ​ 40,460 ​ — Domestic mutual funds ​ $ 75,384 ​ 75,384 ​ — ​ — Municipal bonds ​ $ 1,133 ​ — ​ 1,133 ​ — Federal agency securities ​ $ 9,608 ​ — ​ 9,608 ​ — Other ​ $ 16,351 ​ 13,623 ​ 2,728 ​ — Long-term investments: ​ ​ ​ ​ International equity trust ​ $ 35,873 ​ — ​ 35,873 ​ — Corporate bonds and debt ​ $ 14,022 ​ — ​ 12,656 ​ 1,366 US Treasury securities ​ $ 15,259 ​ 15,259 ​ — ​ — Mortgage backed securities ​ $ 12,021 ​ — ​ 12,021 ​ — Domestic mutual funds ​ $ 277,937 ​ 277,937 ​ — ​ — Federal agency securities ​ $ 257 ​ — ​ 257 ​ — Treasury STRIPS ​ $ 350,532 ​ — ​ 350,532 ​ — Other ​ $ 5,478 ​ 5,478 ​ — ​ — Natural gas swaps ​ $ 63,994 ​ — ​ 63,994 ​ — ​
Schedule of estimated fair values of long-term debt, including current maturities	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ Carrying Fair Carrying Fair ​ ​ Value ​ Value ​ Value ​ Value ​ ​ (in thousands) Long-term debt ​ $ 11,940,359 ​ $ 10,194,954 ​ $ 10,915,054 ​ $ 12,741,046 ​

Derivative instruments (Tables)

Derivative instruments (Tables)	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year	The following table reflects the volume activity of our natural gas derivatives as of December 31, 2022 that is expected to settle or mature each year: ​ ​ ​ ​ ​ ​ Natural Gas ​ ​ Swaps Year ​ (MMBTUs) ​ (in millions) 2023 32.1 2024 27.7 2025 23.3 2026 18.2 2027 6.0 Total 107.3 ​
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 December 31, 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet ​ ​ ​ ​ ​ ​ ​ ​ Location ​ Fair Value ​ ​ ​ ​ 2022 ​ 2021 ​ ​ ​ (dollars in thousands) Assets ​ ​ Natural gas swaps Other current assets ​ $ 35,285 ​ $ 23,596 Natural gas swaps Other deferred charges ​ $ 99,725 ​ $ 40,398 Liabilities ​ ​ Natural gas swaps Other current liabilities ​ $ 3,206 ​ $ — ​
Schedule of the realized gains and (losses) on derivative instruments recognized in margin	The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, 2022, 2021 and 2020. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Revenues and ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Expenses Location ​ ​ 2022 ​ ​ 2021 ​ ​ 2020 ​ ​ (dollars in thousands) Natural gas swaps gains Fuel ​ $ 121,626 ​ $ 31,440 ​ $ 830 Natural gas swaps losses Fuel ​ (6,587) ​ (1,431) ​ (21,179) Total ​ $ 115,039 ​ $ 30,009 ​ $ (20,349) ​
Schedule of unrealized gains and (losses) on derivative instruments deferred on the balance sheet	The following table presents the unrealized (gains) and losses on derivative instruments deferred on the consolidated balance sheets at December 31, 2022 and 2021. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Consolidated Balance ​ ​ ​ ​ ​ ​ ​ ​ Sheet Location ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 ​ 2021 ​ ​ ​ (dollars in thousands) Natural gas swaps Regulatory liability $ 131,804 $ 63,994 Total ​ $ 131,804 ​ $ 63,994

Investments (Tables)

Investments (Tables)	12 Months Ended
	Dec. 31, 2022
Schedule of Investments [Abstract]
Summary of debt and equity securities	The following tables summarize debt and equity securities at December 31, 2022 and 2021. ​ ​ ​ Gross Unrealized 2022 Cost Gains Losses Fair Value ​ ​ (dollars in thousands) 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 ​ ​ ​ ​ Gross Unrealized 2021 Cost Gains Losses Fair Value ​ ​ (dollars in thousands) Equity ​ $ 304,305 ​ $ 280,127 ​ $ (4,682) ​ $ 579,750 Debt ​ 774,580 ​ 4,859 ​ (7,001) ​ 772,438 Other ​ 19,102 ​ — ​ (1) ​ 19,101 Total ​ $ 1,097,987 ​ $ 284,986 ​ $ (11,684) ​ $ 1,371,289 ​
Schedule of contractual maturities of debt securities	The contractual maturities of debt securities, which are included in the estimated fair value table above, at December 31, 2022 and 2021 are as follows: ​ ​ ​ 2022 ​ 2021 ​ Cost Fair Value Cost Fair Value ​ ​ (dollars in thousands) Due within one year ​ $ 367,199 ​ $ 353,180 ​ $ 223,933 ​ $ 222,307 Due after one year through five years ​ 293,523 ​ 275,073 ​ 371,060 ​ 368,574 Due after five years through ten years ​ 66,255 ​ 62,576 ​ 62,679 ​ 62,639 Due after ten years ​ 106,058 ​ 96,209 ​ 116,908 ​ 118,918 Total ​ $ 833,035 ​ $ 787,038 ​ $ 774,580 ​ $ 772,438 ​
Summary of realized gains and losses and proceeds from sales of securities	The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2022, 2021 and 2020: ​ ​ 2022 2021 2020 ​ ​ (dollars in thousands) Gross realized gains ​ $ 10,029 ​ $ 33,501 ​ $ 36,647 Gross realized losses ​ (31,979) ​ (19,985) ​ (16,868) Proceeds from sales ​ 301,128 ​ 913,600 ​ 756,513 ​
Schedule of investments in associated companies	Investments in associated companies were as follows at December 31, 2022 and 2021: ​ ​ 2022 2021 ​ ​ (dollars in thousands) National Rural Utilities Cooperative Finance Corporation (CFC) ​ $ 24,081 ​ $ 24,081 CT Parts, LLC ​ 6,574 ​ 7,049 Georgia Transmission Corporation ​ 38,287 ​ 35,696 Georgia System Operations Corporation ​ 7,750 ​ 6,500 Other ​ 2,245 ​ 2,500 Total ​ $ 78,937 ​ $ 75,826 ​

Income taxes (Tables)

Income taxes (Tables)	12 Months Ended
	Dec. 31, 2022
Income Tax Disclosure [Abstract]
Summary of difference between statutory federal income tax rate on income before income taxes and effective income tax rate	The difference between the statutory federal income tax rate on income before income taxes and our effective income tax rate is summarized as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 2020 Statutory federal income tax rate 21.0 % 21.0 % 21.0 % Patronage exclusion (21.0) % (21.0) % (21.0) % Effective income tax rate 0.0 % 0.0 % 0.0 % ​
Schedule of components of net deferred tax assets and liabilities	The components of our net deferred tax assets and liabilities as of December 31, 2022 and 2021 were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ 2022 2021 Deferred tax assets ​ ​ Net operating losses ​ $ 115,080 ​ $ — Obligation related to asset retirements ​ 345,879 ​ 331,311 Advance payments ​ 183,833 ​ 175,077 Other regulatory liabilities ​ 18,687 ​ 54,611 Other assets ​ 30,373 ​ 24,838 Deferred tax assets ​ 693,852 ​ 585,837 Less: Valuation allowance ​ — ​ — Net deferred tax assets ​ $ 693,852 ​ $ 585,837 Deferred tax liabilities ​ ​ Fixed assets and intangibles ​ $ (140,095) ​ $ (40,655) Right-of-use assets-finance leases ​ (77,923) ​ (77,923) Other regulatory asset ​ (343,230) ​ (338,291) Other liabilities ​ (15,352) ​ (17,984) Deferred tax liabilities ​ (576,600) ​ (474,853) Net deferred tax assets (liabilities) ​ $ 117,252 ​ $ 110,984 Less: Patronage exclusion ​ (117,252) ​ (110,984) Net deferred taxes ​ $ — ​ $ — ​

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Schedule of balance sheet impact of leases	For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. ​ ​ ​ ​ ​ ​ ​ ​ Classification ​ 2022 2021 ​ (dollars in thousands) Right-of-use assets - Finance leases ​ ​ Right-of-use assets ​ $ 302,732 ​ $ 302,732 Less: Accumulated provision for depreciation ​ (272,876) ​ (267,606) Total finance lease assets ​ $ 29,856 ​ $ 35,126 ​ ​ ​ ​ ​ ​ ​ Lease liabilities - Finance leases ​ ​ Obligations under finance leases ​ $ 52,937 ​ $ 61,335 Long-term debt and finance leases due within one year ​ 8,398 ​ 7,541 Total finance lease liabilities ​ $ 61,335 ​ $ 68,876 ​ ​ ​ ​ ​ ​ ​ ​ ​ Classification 2022 2021 ​ ​ (dollars in thousands) Right-of-use assets - Operating leases ​ ​ Electric plant in service, net ​ $ 3,326 ​ $ 2,293 Total operating lease assets ​ $ 3,326 ​ $ 2,293 ​ ​ ​ ​ ​ ​ ​ Lease liabilities - Operating leases ​ ​ Capitalization - Other ​ $ 2,256 ​ $ 1,550 Other current liabilities ​ 1,164 ​ 838 Total operating lease liabilities ​ $ 3,420 ​ $ 2,388 ​
Schedule of lease cost	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ ​ ​ (dollars in thousands) Lease Cost Classification ​ ​ Finance lease cost: ​ ​ Amortization of leased assets Depreciation and amortization ​ $ 7,542 ​ $ 6,420 Interest on lease liabilities Interest expense ​ $ 7,408 ​ $ 8,177 ​ ​ ​ ​ ​ ​ ​ ​ ​ Operating lease cost Inventory(1) & production expense ​ $ 995 ​ $ 1,079 Total lease cost ​ $ 15,945 ​ $ 15,676 (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. ​ ​ ​ ​ ​ ​ ​ ​ December 31, 2022 December 31, 2021 Lease Term and Discount Rate ​ ​ ​ ​ ​ ​ ​ Weighted-average remaining lease term (in years): ​ Finance leases 5.94 6.90 ​ Operating leases 6.44 8.01 ​ ​ ​ ​ ​ ​ ​ Weighted-average discount rate: ​ Finance leases 11.05 % 11.05 % Operating leases 5.52 % 4.73 % ​
Summary of lease terms and discount rates	​
Schedule of cash paid for amounts included in the measurement of lease liabilities	​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ (dollars in thousands) Other Information: ​ ​ Cash paid for amounts included in the measurement of lease liabilities ​ ​ Operating cash flows from finance leases ​ $ 7,408 ​ $ 8,177 Operating cash flows from operating leases ​ $ 1,009 ​ $ 1,129 Financing cash flows from finance leases ​ $ 7,541 ​ $ 6,772 ​ ​ ​ ​ ​ ​ ​ Right-of-use assets obtained in exchange for new operating lease liabilities ​ $ 1,954 ​ $ — ​
Schedule of maturities of finance operating lease liabilities	Maturity analysis of our finance and operating lease liabilities as of December 31, 2022 is as follows: ​ Year Ending December 31, Finance Leases Operating Leases Total ​ ​ (dollars in thousands) 2023 ​ $ 14,949 ​ $ 1,324 ​ $ 16,273 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 ​ $ 4,105 ​ $ 89,533 Less: imputed interest ​ (24,093) ​ (685) ​ (24,778) Present value of lease liabilities ​ $ 61,335 ​ $ 3,420 ​ $ 64,755 ​
Schedule of lessor's income from leases	Lease income recognized during 2022 and 2021 was as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 Lease income ​ $ 6,539 ​ $ 6,312

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Schedule of maturities for long-term debt and finance lease obligations	Maturities for long-term debt and finance lease obligations through 2027 are as follows: ​ ​ 2023 2024 2025 2026 2027 ​ ​ (dollars in thousands) FFB ​ $ 312,695 ​ $ 308,892 ​ $ 282,399 ​ $ 262,793 ​ $ 271,623 FMBs ​ 1,010 ​ 63,510 ​ 62,500 ​ 62,500 ​ 62,500 PCRBs ​ — ​ — ​ — ​ — ​ — ​ ​ $ 313,705 ​ $ 372,402 ​ $ 344,899 ​ $ 325,293 ​ $ 334,123 Finance Leases ​ 8,398 ​ 9,351 ​ 10,413 ​ 11,595 ​ 12,912 Total ​ $ 322,103 ​ $ 381,753 ​ $ 355,312 ​ $ 336,888 ​ $ 347,035 ​
Schedule of long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts	Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts at December 31, 2022 and December 31, 2021 are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ ​ Unamortized Debt ​ ​ Unamortized Debt ​ ​ ​ ​ ​ Issuance Costs ​ ​ ​ ​ Issuance Costs ​ ​ ​ ​ ​ and ​ ​ ​ ​ and ​ ​ Principal ​ Debt Discounts ​ Principal ​ Debt Discounts ​ ​ (dollars in thousands) FFB ​ $ 7,084,148 ​ $ 52,690 ​ $ 6,526,858 ​ $ 55,159 FMBs ​ 4,152,021 ​ 52,480 ​ 3,653,031 ​ 46,985 PCRBs ​ 704,190 ​ 8,972 ​ 735,165 ​ 9,765 ​ ​ $ 11,940,359 ​ $ 114,142 ​ $ 10,915,054 ​ $ 111,909 ​

Electric plant, construction _2

Electric plant, construction and related agreements (Tables)	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Summary of plant investments and related accumulated depreciation	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2022 2021 ​ ​ ​ Accumulated ​ ​ Accumulated Plant ​ Investment ​ Depreciation ​ Investment ​ Depreciation ​ ​ (dollars in thousands) In-service (1) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Owned property ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Vogtle Units No. 1 & No. 2 ​ $ 3,024,112 ​ $ (1,916,942) ​ $ 3,010,843 ​ $ (1,881,324) (Nuclear – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Vogtle Units No. 3 & No. 4 ​ 58,189 ​ (8,627) ​ 58,199 ​ (7,290) (Nuclear – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hatch Units No. 1 & No. 2 ​ 991,852 ​ (533,771) ​ 973,682 ​ (503,871) (Nuclear – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Wansley Units No. 1 & No. 2 (2) ​ 20,312 ​ (15,337) ​ 820,110 ​ (649,301) (Fossil – 30% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Scherer Unit No. 1 ​ 1,378,904 ​ (636,799) ​ 1,415,115 ​ (638,443) (Fossil – 60% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Doyle (Combustion Turbine - 100% ownership) ​ 145,780 ​ (124,306) ​ 144,711 ​ (120,527) Rocky Mountain Units No. 1, No. 2 & No. 3 ​ 616,278 ​ (296,624) ​ 615,485 ​ (284,749) (Hydro – 75% ownership) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Hartwell (Combustion Turbine - 100% ownership) ​ 232,532 ​ (125,092) ​ 227,834 ​ (121,174) Hawk Road (Combustion Turbine - 100% ownership) ​ 269,837 ​ (74,685) ​ 266,149 ​ (69,194) Talbot (Combustion Turbine - 100% ownership) ​ 301,869 ​ (162,137) ​ 300,335 ​ (158,270) Chattahoochee (Combined cycle - 100% ownership) ​ 324,310 ​ (171,272) ​ 319,550 ​ (166,859) Effingham (Combined cycle - 100% ownership) ​ 339,189 ​ (121,318) ​ 337,614 ​ (112,057) Smith (Combined cycle - 100% ownership) ​ 686,517 ​ (208,142) ​ 672,184 ​ (190,760) Wansley (Combustion Turbine – 30% ownership) (2) ​ — ​ — ​ 3,942 ​ (3,889) Washington County (Combustion Turbine – 100% ownership) ​ 170,432 ​ (88,585) ​ — ​ — Transmission plant ​ 107,992 ​ (64,785) ​ 102,966 ​ (62,457) Other ​ 106,424 ​ (65,922) ​ 104,372 ​ (62,885) Property under finance lease: ​ ​ ​ ​ Scherer Unit No. 2 (Fossil – 60% leasehold) ​ 794,830 ​ (569,245) ​ 795,301 ​ (532,674) Total in-service ​ $ 9,569,359 ​ $ (5,183,589) ​ $ 10,168,392 ​ $ (5,565,724) Construction work in progress ​ ​ ​ ​ Vogtle Units No. 3 & No. 4 ​ $ 7,583,291 ​ ​ $ 6,680,014 ​ Environmental and other generation improvements ​ 132,744 ​ ​ 99,378 ​ Total construction work in progress ​ $ 7,716,035 ​ ​ $ 6,779,392 ​ (1) Amounts include plant acquisition adjustments at December 31, 2022 of $280,396,000 and December 31, 2021 of $248,000,000 . (2) Plant Wansley Units No. 1 and No. 2 and the combustion turbine were retired on August 31, 2022. The remaining balance represents land and certain asset retirement obligations.
Schedule of project budget and actual costs	The table below shows our project budget and actual costs through December 31, 2022 for our share of the project. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Actual Costs at December ​ ​ Project Budget (Tender) ​ 31, 2022 ​ ​ (in millions) Construction Costs (1) ​ $ 6,554 ​ $ 6,147 Freeze Capital Credit (2) ​ ​ (528) ​ ​ — Financing Costs ​ 2,025 ​ 1,770 Subtotal ​ $ 8,051 ​ $ 7,917 Deferred Training Costs ​ 47 ​ 46 Total Project Costs Before Contingency ​ $ 8,098 ​ $ 7,963 ​ ​ ​ ​ ​ ​ ​ Oglethorpe Contingency ​ $ 2 ​ $ — Totals ​ $ 8,100 ​ $ 7,963 (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. ​

Commitments (Tables)

Commitments (Tables)	12 Months Ended
	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Schedule of estimated commitments	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Asset ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gas ​ Maintenance ​ Retirement ​ Finance and ​ ​ Coal ​ Nuclear Fuel ​ Transportation ​ Agreements ​ Obligations ​ Operating Leases ​ ​ (dollars in thousands) 2023 ​ $ 26,891 ​ $ 78,780 ​ $ 63,850 ​ $ 29,720 ​ $ 16,709 ​ $ 16,273 2024 ​ 26,070 ​ 39,690 ​ 62,818 ​ 57,749 ​ 52,003 ​ 15,799 2025 ​ 10,426 ​ 32,280 ​ 62,775 ​ 43,025 ​ 46,128 ​ 15,590 2026 ​ — ​ 28,980 ​ 68,872 ​ 15,736 ​ 49,445 ​ 15,299 2027 ​ — ​ 26,580 ​ 67,188 ​ 3,237 ​ 67,384 ​ 15,021 Thereafter ​ — ​ 67,170 ​ 824,627 ​ 316,160 ​ 3,416,582 ​ 11,551

Plant Acquisition (Tables)

Plant Acquisition (Tables)	12 Months Ended
	Dec. 31, 2022
Business Combination and Asset Acquisition [Abstract]
Schedule of identifiable assets acquired and liabilities assumed	​ ​ ​ ​ ​ Classification ​ ​ ​ (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: ​ Electric plant in service, net ​ $ 80,878 Inventories, at average cost ​ 981 Other current assets ​ 417 Power purchase and sale agreement ​ 4,708 Other current liabilities ​ (158) Total identifiable net assets ​ $ 86,826

Quarterly financial data (una_2

Quarterly financial data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2022
Quarterly Financial Data [Abstract]
Summary of quarterly financial information	​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ First ​ Second ​ Third ​ Fourth ​ ​ Quarter ​ Quarter ​ Quarter ​ Quarter ​ (dollars in thousands) 2022 ​ ​ ​ ​ Operating revenues ​ $ 420,442 ​ $ 533,128 ​ $ 704,265 ​ $ 472,302 Operating margin ​ 57,845 ​ 54,269 ​ 64,553 ​ 17,384 Net margin ​ 21,980 ​ 18,167 ​ 32,097 ​ (10,540) 2021 ​ ​ ​ ​ Operating revenues ​ $ 376,331 ​ $ 358,127 ​ $ 460,822 ​ $ 409,583 Operating margin ​ 64,573 ​ 53,035 ​ 46,025 ​ 30,748 Net margin ​ 25,958 ​ 13,145 ​ 8,907 ​ 9,771

Summary of significant accoun_4

Summary of significant accounting policies - Business Description (Details) person in Millions	12 Months Ended
	Dec. 31, 2022 person item MW
Business description
Number of electric distribution cooperative members | item	38
Summer planning reserve capacity of generating units (in megawatts)	7,744
Number of people to whom energy is distributed on a retail basis by the entity's members | person	4.4
Smarr EMC
Business description
Summer planning reserve capacity of generating units (in megawatts)	733
Green Power EMC
Business description
Summer planning reserve capacity of generating units (in megawatts)	584
Green Power EMC | Solar energy
Business description
Summer planning reserve capacity of generating units (in megawatts)	552

Summary of significant accoun_5

Summary of significant accounting policies - Patronage capital and membership fees and Margin policy (Details)	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021	Dec. 31, 2020
Patronage capital and membership fees
Membership fees	$ 190
Minimum equity as a percentage of total long-term debt and equities for distributions of patronage capital	20%
Maximum percentage of aggregate net margins in which specified percentage of total long-term debt and equities cannot exceed on or after distributions expended	35%
Minimum equity as a percentage of total long-term debt and equities after distributions of patronage capital	30%
Margin policy
Minimum margins for interest ratio under the first mortgage indenture	1.10	1.10	1.10
Achieved margins for interest ratio	1.14	1.14	1.14

Summary of significant accoun_6

Summary of significant accounting policies - Revenue recognition (Details)	12 Months Ended			60 Months Ended
	Dec. 31, 2022 USD ($) item	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2022 USD ($)
Revenue Recognition
Number of electric distribution cooperative members | item	38
Number of services provided | item	2
Energy supplied to members, percent	58%	62%	57%
Minimum margins for interest ratio under the first mortgage indenture	1.10	1.10	1.10
Targeted margins for interest ratio	1.14	1.14	1.14
Refund liability	$ 28,471,000	$ 30,029,000		$ 28,471,000
Total revenues	2,130,137,000	1,604,863,000	$ 1,377,618,000
Vogtle Units No. 3 & No. 4
Operating revenues
Recovery of financing costs	14,796,000	15,693,000	14,684,000
Cumulative recovery of financing costs	$ 126,432,000
Additional collection period (in years)	5 years
Billed amount	$ 11,774,000	143,000,000	125,842,000	369,102,000
Members
Revenue Recognition
Total revenues	1,974,683,000	1,557,109,000	1,377,010,000
Operating revenues
Receivables	$ 187,401,000	$ 143,715,000	$ 135,462,000	187,401,000
Jackson EMC | Total operating revenues | Revenues of members
Operating revenues
Concentration risk (as a percent)	16%	15.20%	15.20%
GreyStone Power Corporation, an EMC | Total operating revenues | Revenues of members
Operating revenues
Concentration risk (as a percent)	10%	8.70%	8.70%
Cobb EMC | Total operating revenues | Revenues of members
Operating revenues
Concentration risk (as a percent)	9.50%	12.30%	13.20%
Non-Members
Revenue Recognition
Total revenues	$ 155,454,000	$ 47,754,000	$ 608,000
Operating revenues
Receivables	32,614,000			$ 32,614,000
Capacity revenues | Members
Revenue Recognition
Total revenues	984,036,000	946,662,000	971,071,000
Capacity revenues | Non-Members
Revenue Recognition
Total revenues	82,000
Energy revenues | Members
Revenue Recognition
Total revenues	990,647,000	610,447,000	405,939,000
Energy revenues | Non-Members
Revenue Recognition
Total revenues	$ 155,372,000	$ 47,754,000	$ 608,000

Summary of significant accoun_7

Summary of significant accounting policies - Receivables (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Receivables
Impairment losses	$ 0	$ 0	$ 0
Members
Receivables
Receivables	187,401,000	$ 143,715,000	$ 135,462,000
Non-Members
Receivables
Receivables	$ 32,614,000

Summary of significant accoun_8

Summary of significant accounting policies - Nuclear fuel cost (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Nuclear fuel cost
Nuclear fuel expense	$ 73,871,000	$ 77,366,000	$ 75,968,000
Estimated share of claims outstanding				$ 84,000,000
Damages receivable	$ 0	$ 0

Summary of significant accoun_9

Summary of significant accounting policies - Asset retirement obligations and other retirement costs (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset retirement obligations
Balance at the beginning of the period	$ 1,287,143,000	$ 1,135,983,000
Liabilities settled	(10,318,000)	(12,404,000)
Liabilities settled	10,318,000	12,404,000
Accretion	55,953,000	56,086,000	$ 54,475,000
Deferred accretion	479,000	(199,000)
Change in cash flow estimates	10,486,000	107,677,000
Balance at the end of the period	1,343,743,000	1,287,143,000	1,135,983,000
Coal Combustion Residuals
Increase in the obligation for coal ash decommissioning	16,301,000	102,185,000
Fund balances for coal ash pond and landfill decommissioning	153,208,000	140,474,000
Hatch Unit No. 1
Nuclear Decommissioning
Estimated costs based on site study	302,000,000
Hatch Unit No. 1 | Radiated structures
Nuclear Decommissioning
Estimated costs based on site study	227,000,000
Hatch Unit No. 1 | Spent fuel management
Nuclear Decommissioning
Estimated costs based on site study	60,000,000
Hatch Unit No. 1 | Non-radiated structures
Nuclear Decommissioning
Estimated costs based on site study	15,000,000
Hatch Unit No. 2
Nuclear Decommissioning
Estimated costs based on site study	308,000,000
Hatch Unit No. 2 | Radiated structures
Nuclear Decommissioning
Estimated costs based on site study	236,000,000
Hatch Unit No. 2 | Spent fuel management
Nuclear Decommissioning
Estimated costs based on site study	51,000,000
Hatch Unit No. 2 | Non-radiated structures
Nuclear Decommissioning
Estimated costs based on site study	21,000,000
Vogtle Unit No. 1
Nuclear Decommissioning
Estimated costs based on site study	282,000,000
Vogtle Unit No. 1 | Radiated structures
Nuclear Decommissioning
Estimated costs based on site study	200,000,000
Vogtle Unit No. 1 | Spent fuel management
Nuclear Decommissioning
Estimated costs based on site study	58,000,000
Vogtle Unit No. 1 | Non-radiated structures
Nuclear Decommissioning
Estimated costs based on site study	24,000,000
Vogtle Unit No. 2
Nuclear Decommissioning
Estimated costs based on site study	297,000,000
Vogtle Unit No. 2 | Radiated structures
Nuclear Decommissioning
Estimated costs based on site study	213,000,000
Vogtle Unit No. 2 | Spent fuel management
Nuclear Decommissioning
Estimated costs based on site study	53,000,000
Vogtle Unit No. 2 | Non-radiated structures
Nuclear Decommissioning
Estimated costs based on site study	31,000,000
Nuclear
Asset retirement obligations
Balance at the beginning of the period	778,214,000	738,217,000
Accretion	41,892,000	43,206,000
Change in cash flow estimates		(3,209,000)
Balance at the end of the period	820,106,000	778,214,000	738,217,000
Coal Ash Pond
Asset retirement obligations
Balance at the beginning of the period	442,686,000	346,589,000
Liabilities settled	(10,134,000)	(17,046,000)
Liabilities settled	10,134,000	17,046,000
Accretion	12,196,000	11,157,000
Deferred accretion	479,000	(199,000)
Change in cash flow estimates	16,301,000	102,185,000
Balance at the end of the period	461,528,000	442,686,000	346,589,000
Other
Asset retirement obligations
Balance at the beginning of the period	66,243,000	51,177,000
Liabilities settled	(184,000)	(4,642,000)
Liabilities settled	184,000	4,642,000
Accretion	1,865,000	1,723,000
Change in cash flow estimates	(5,815,000)	8,701,000
Balance at the end of the period	$ 62,109,000	$ 66,243,000	$ 51,177,000

Summary of significant accou_10

Summary of significant accounting policies - Nuclear decommissioning funds (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Nuclear decommissioning funds
Additional contribution to external trust funds	$ 2,643
Additional amount collected for nuclear decommissioning	$ 8,350	$ 9,750
Percentage of decommissioning fund classified as equity	69%	71%
Percentage of decommissioning funds classified as fixed income securities	31%	29%
External and Internal Trust Funds:
Purchases	$ 204,500	$ 675,153	$ 578,610
Fair Value	$ 540,716	659,910
Average annualized rate of return over the past ten years	5.90%
Average annualized rate of return since inception	5.80%
External Trust Funds
External and Internal Trust Funds:
Cost		427,476	409,214
Cost		(427,476)	(409,214)
Purchases	$ 204,500	675,153
Net Proceeds	(209,963)	(656,891)
Unrealized Gain(Loss)	118,703	232,434
Fair Value	540,716	659,910
Net realized gains or losses, interest income and dividends, contributions and fees	5,463	18,261
Internal Funds
External and Internal Trust Funds:
Cost		115,770	101,114
Cost		(115,770)	(101,114)
Purchases	76,207	204,150
Net Proceeds	(69,823)	(189,494)
Unrealized Gain(Loss)	16,254	44,916
Fair Value	138,408	160,686
Net realized gains or losses, interest income and dividends, contributions and fees	6,384	14,656
Equity | External Trust Funds
External and Internal Trust Funds:
Cost		223,336	212,387
Cost		(223,336)	(212,387)
Purchases	9,255	50,309
Net Proceeds	(3,655)	(39,360)
Unrealized Gain(Loss)	131,572	230,710
Fair Value	360,508	454,046
Equity | Internal Funds
External and Internal Trust Funds:
Cost		68,914	50,647
Cost		(68,914)	(50,647)
Net Proceeds	10,005	18,267
Unrealized Gain(Loss)	18,995	44,735
Fair Value	97,914	113,649
Debt | External Trust Funds
External and Internal Trust Funds:
Cost		204,935	196,810
Cost		(204,935)	(196,810)
Purchases	191,958	583,003
Net Proceeds	(203,907)	(574,878)
Unrealized Gain(Loss)	(12,869)	1,724
Fair Value	180,117	206,659
Debt | Internal Funds
External and Internal Trust Funds:
Cost		46,856	50,467
Cost		(46,856)	(50,467)
Purchases	76,207	204,150
Net Proceeds	(79,828)	(207,761)
Unrealized Gain(Loss)	(2,741)	181
Fair Value	40,494	47,037
Other | External Trust Funds
External and Internal Trust Funds:
Cost		795	17
Cost		(795)	$ (17)
Purchases	3,287	41,841
Net Proceeds	(2,401)	(42,653)
Fair Value	$ 91	$ (795)

Summary of significant accou_11

Summary of significant accounting policies - Depreciation and Electric plant (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Depreciation
Depreciation expense	$ 278,452,000	$ 269,280,000	$ 242,822,000
Regulatory assets	$ 1,212,305,000	$ 1,008,790,000
Electric plant
Allowance for funds used during construction (as a percent)	4.03%	3.90%	4%
Depreciation expense
Depreciation
Regulatory assets	$ 35,549,000	$ 36,973,000
Steam production
Depreciation
Annual depreciation rates (as a percent)	13.77%	14.47%	2.58%
Steam production | Minimum
Depreciation
Remaining Useful Life Range in years	20 years
Steam production | Maximum
Depreciation
Remaining Useful Life Range in years	22 years
Nuclear production
Depreciation
Annual depreciation rates (as a percent)	2.17%	2.18%	1.93%
Nuclear production | Minimum
Depreciation
Remaining Useful Life Range in years	12 years
Nuclear production | Maximum
Depreciation
Remaining Useful Life Range in years	27 years
Hydro production
Depreciation
Remaining Useful Life Range in years	44 years
Annual depreciation rates (as a percent)	2%	2%	2%
Other production
Depreciation
Annual depreciation rates (as a percent)	2.68%	2.60%	2.61%
Other production | Minimum
Depreciation
Remaining Useful Life Range in years	17 years
Other production | Maximum
Depreciation
Remaining Useful Life Range in years	26 years
Transmission
Depreciation
Annual depreciation rates (as a percent)	2.75%	2.75%	2.75%
Transmission | Minimum
Depreciation
Remaining Useful Life Range in years	12 years
Transmission | Maximum
Depreciation
Remaining Useful Life Range in years	27 years
General | Minimum
Depreciation
Remaining Useful Life Range in years	1 year
Annual depreciation rates (as a percent)	2%	2%	2%
General | Maximum
Depreciation
Remaining Useful Life Range in years	43 years
Annual depreciation rates (as a percent)	33.33%	33.33%	33.33%
Wansley
Depreciation
Depreciation expense	$ 8,120,000
Wansley | Depreciation expense
Depreciation
Regulatory assets	$ 361,784,000	$ 204,891,000

Summary of significant accou_12

Summary of significant accounting policies - Restricted investments (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Oct. 01, 2022	Dec. 31, 2021	Oct. 01, 2021	Sep. 30, 2021
Summary of significant accounting policies
Investment interest rate					4%
Restricted investments	$ 74,031		$ 320,052
Restricted cash and short-term investments	$ 74,031		$ 246,350
Treasury rate
Summary of significant accounting policies
Investment interest rate		4.05%		0.09%

Summary of significant accou_13

Summary of significant accounting policies - Reconciliation of cash, cash equivalents and restricted cash (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Cash and cash equivalents	$ 595,381	$ 579,350
Restricted cash included in restricted cash and short-term investments	30,400	1,800
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows	$ 625,781	$ 581,150	$ 405,511	$ 448,612

Summary of significant accou_14

Summary of significant accounting policies - Inventories (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounting Policies [Abstract]
Fossil fuels inventories	$ 64,386	$ 44,601
Spare parts	$ 233,565	$ 215,925

Summary of significant accou_15

Summary of significant accounting policies - Regulatory assets and liabilities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 1,212,305	$ 1,008,790
Total Regulatory Liabilities	792,190	849,449
Net Regulatory Assets	420,115	159,341
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	35,580	22,197
Deferral of effects on net margin
Regulatory Assets and Liabilities
Total Regulatory Liabilities	16,636	17,253
Deferral of effects on net margin | Effingham County Power
Regulatory Assets and Liabilities
Total Regulatory Liabilities	14,825
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	74,584	73,059
Amortization on capital leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	5,557	8,457
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	154,514	138,897
Nuclear
Regulatory Assets and Liabilities
Total Regulatory Liabilities		164,256
Revenue deferral plan
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 357,460	359,799
Amortization period, other regulatory liabilities	5 years
Natural gas hedge
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 131,804	63,994
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 1,230	1,537
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory liabilities	4 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 29,494	33,200
Premium and loss on reacquired debt | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	21 years
Amortization on financing leases
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 31,908	34,179
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 29,317	31,956
Coal-fired maintenance outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	60 months
Nuclear refueling outage costs | Minimum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	18 months
Nuclear refueling outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	24 months
Asset retirement obligations - Ashpond and other
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 353,212	335,231
Nuclear
Regulatory Assets and Liabilities
Total Regulatory Assets	32,192
Depreciation expense
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 35,549	36,973
Depreciation expense | Plant Vogtle
Regulatory Assets and Liabilities
Operating license expected extension period for Plant Vogtle	20 years
Operating license period	40 years
Depreciation expense | Wansley
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 361,784	204,891
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units No. 3 & No. 4
Regulatory Assets and Liabilities
Total Regulatory Assets	54,701	55,857
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	136,827	131,556
Deferral of effects on net margin | Smith Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Assets	136,730	142,675
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 10,591	$ 2,272
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	27 years

Summary of significant accou_16

Summary of significant accounting policies - Related parties (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) item	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Related parties
Number of electric distribution cooperative members	38
Georgia Transmission Corporation
Related parties
Number of electric distribution cooperative members	38
Expenses incurred for transmission services, system operations services and administrative support services | $	$ 40,774	$ 39,677	$ 37,931
Georgia System Operations Corporation
Related parties
Number of electric distribution cooperative members	38
Expenses incurred for transmission services, system operations services and administrative support services | $	$ 27,416	$ 26,936	$ 27,104

Fair Value - Asset and liabilit

Fair Value - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair value
Nuclear decommissioning trust fund	$ 540,716	$ 659,910
Long-term investments	669,479	711,379
Short-term investments	61,702	0
International equity trust
Fair value
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Natural gas swaps
Fair value
Derivative liabilities	$ 131,804	63,994
Recurring basis | Domestic equity
Fair value
Nuclear decommissioning trust fund	204,129	249,999
Recurring basis | International equity trust
Fair value
Nuclear decommissioning trust fund	111,266	140,718
Long-term investments	33,606	35,873
Recurring basis | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	60,806	72,936
Long-term investments	10,473	14,022
Recurring basis | US Treasury securities
Fair value
Nuclear decommissioning trust fund	49,775	53,321
Long-term investments	15,488	15,259
Recurring basis | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	41,210	40,460
Long-term investments	12,113	12,021
Recurring basis | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	57,348	75,384
Long-term investments	302,302	277,937
Recurring basis | Municipal bonds
Fair value
Nuclear decommissioning trust fund		1,133
Recurring basis | Federal agency securities
Fair value
Nuclear decommissioning trust fund	2,037	9,608
Long-term investments		257
Recurring basis | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,890
Long-term investments	1,976
Recurring basis | International mutual funds
Fair value
Nuclear decommissioning trust fund	653
Recurring basis | Treasury STRIPS
Fair value
Long-term investments	293,281	350,532
Short-term investments	61,702
Recurring basis | Other
Fair value
Nuclear decommissioning trust fund	10,602	16,351
Long-term investments	240	5,478
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value
Nuclear decommissioning trust fund	204,129	249,999
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	49,775	53,321
Long-term investments	15,488	15,259
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	57,348	75,384
Long-term investments	302,302	277,937
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value
Nuclear decommissioning trust fund	10,602	13,623
Long-term investments	240	5,478
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value
Derivative liabilities	131,804	63,994
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value
Nuclear decommissioning trust fund	111,266	140,718
Long-term investments	33,606	35,873
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	60,788	72,369
Long-term investments	10,473	12,656
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	41,210	40,460
Long-term investments	12,113	12,021
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds
Fair value
Nuclear decommissioning trust fund		1,133
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	2,037	9,608
Long-term investments		257
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	2,890
Long-term investments	1,976
Recurring basis | Significant Other Observable Inputs (Level 2) | International mutual funds
Fair value
Nuclear decommissioning trust fund	653
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS
Fair value
Long-term investments	293,281	350,532
Short-term investments	61,702
Recurring basis | Significant Other Observable Inputs (Level 2) | Other
Fair value
Nuclear decommissioning trust fund		2,728
Recurring basis | Significant Unobservable Inputs (Level 3) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	$ 18	567
Long-term investments		$ 1,366

Fair Value - Estimated fair val

Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Carrying Value
Fair Value
Long-term debt	$ 11,940,359	$ 10,915,054
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value
Long-term debt	$ 10,194,954	$ 12,741,046

Derivative instruments - Gas he

Derivative instruments - Gas hedges (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) MMBTU	Dec. 31, 2021 USD ($)
Derivative Instruments
Derivative asset | $	$ 131,804	$ 63,994
Credit collateral posted | $	$ 30,400	$ 1,800
Notional volume of natural gas derivatives (in MMBTUs)	107.3
2023
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	32.1
2024
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	27.7
2025
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	23.3
2026
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	18.2
2027
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	6

Derivative instruments - Fair v

Derivative instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Assets:
Assets	$ 131,804	$ 63,994
Not designated as hedges
Liabilities:
Liabilities	3,206
Not designated as hedges | Other current assets
Assets:
Assets	35,285	23,596
Not designated as hedges | Other deferred charges
Assets:
Assets	$ 99,725	$ 40,398

Derivative instruments - Realiz

Derivative instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments	$ 131,804	$ 63,994
Natural gas swaps
Gains and (losses) on derivative instruments
Gains	121,626	31,440	$ 830
Losses	(6,587)	(1,431)	(21,179)
Total	115,039	30,009	$ (20,349)
Natural gas swaps | Regulatory liability
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments	$ 131,804	$ 63,994

Investments - Investments in De

Investments - Investments in Debt and Equity Securities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Cost
Equity	$ 323,907	$ 304,305
Debt	833,035	774,580
Other	10,445	19,102
Total	1,167,387	1,097,987
Gross Unrealized Gains
Equity	159,445	280,127
Debt	372	4,859
Other	20
Total	159,837	284,986
Gross Unrealized Losses
Equity	(8,949)	(4,682)
Debt	(46,369)	(7,001)
Other	(9)	(1)
Total	(55,327)	(11,684)
Fair Value
Equity	474,403	579,750
Debt	787,038	772,438
Other	10,456	19,101
Total	$ 1,271,897	$ 1,371,289

Investments - Contractual Matur

Investments - Contractual Maturities of Debt Securities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Cost
Due within one year	$ 367,199	$ 223,933
Due after one year through five years	293,523	371,060
Due after five years through ten years	66,255	62,679
Due after ten years	106,058	116,908
Total	833,035	774,580
Fair Value
Due within one year	353,180	222,307
Due after one year through five years	275,073	368,574
Due after five years through ten years	62,576	62,639
Due after ten years	96,209	118,918
Total	$ 787,038	$ 772,438

Investments - Gross realized ga

Investments - Gross realized gains, losses and proceeds from sales of securities (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Schedule of Investments [Abstract]
Gross realized gains	$ 10,029	$ 33,501	$ 36,647
Gross realized losses	(31,979)	(19,985)	(16,868)
Proceeds from sales	$ 301,128	$ 913,600	$ 756,513

Investments - Investment in ass

Investments - Investment in associated companies (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Investment in associated companies
Investment in associated companies	$ 78,937	$ 75,826
National Rural Utilities Cooperative Finance Corporation (CFC)
Investment in associated companies
Investment in associated companies	24,081	24,081
CT Parts, LLC
Investment in associated companies
Investment in associated companies	6,574	7,049
Georgia Transmission Corporation
Investment in associated companies
Investment in associated companies	38,287	35,696
Georgia System Operations Corporation
Investment in associated companies
Investment in associated companies	7,750	6,500
Other
Investment in associated companies
Investment in associated companies	$ 2,245	$ 2,500

Investments - Rocky Mountain tr

Investments - Rocky Mountain transactions (Details) - Rocky Mountain	2 Months Ended	12 Months Ended
	Jan. 31, 1997 lease trust item	Dec. 31, 2012 USD ($) lease installment
Rocky Mountain transactions
Number of long-term lease transactions | lease	6	6
Percentage of undivided ownership interest	74.61%
Number of separate owner trusts to whom undivided interest was leased | trust	6
Number of investors in ownership trusts | item	3
Term of lease as a percentage of the estimated useful life of the jointly owned utility plant	120%
Term of lease	30 years
Number of leases terminated prior to end of lease term | lease		5
Percentage of leases which remained in place		10%
Basic rental payments due		$ 19,565,000
Purchase option price		112,000,000
Outstanding loan amount		$ 74,000,000
Percentage to be purchased under first option if financing cannot be arranged		49%
Maximum
Rocky Mountain transactions
Additional term of sublease		16 years
AIG Matched Funding Corp
Rocky Mountain transactions
Fund amount under payment undertaking agreement		$ 74,000,000
Fund amount under equity funding agreement		$ 37,928,000
Number of installments available to pay to the owner trust | installment		5

Income taxes - Statutory federa

Income taxes - Statutory federal and effective income tax rate and components of deferred tax assets and liabilities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Current period income tax expense	$ 0
Current income tax liability	$ 0
Difference between statutory federal income tax rate on income before income taxes and effective income tax rate
Statutory federal income tax rate	21%	21%	21%
Patronage exclusion	(21.00%)	(21.00%)	(21.00%)
Effective income tax rate	0%	0%	0%
Deferred tax assets
Net operating losses	$ 115,080,000
Obligation related to asset retirements	345,879,000	$ 331,311,000
Advance payments	183,833,000	175,077,000
Other regulatory liabilities	18,687,000	54,611,000
Other assets	30,373,000	24,838,000
Deferred tax assets	693,852,000	585,837,000
Net deferred tax assets	693,852,000	585,837,000
Deferred tax liabilities
Fixed assets and intangibles	(140,095,000)	(40,655,000)
Right-of-use assets-finance leases	(77,923,000)	(77,923,000)
Other regulatory asset	(343,230,000)	(338,291,000)
Other liabilities	(15,352,000)	(17,984,000)
Deferred tax liabilities	(576,600,000)	(474,853,000)
Net deferred tax assets (liabilities)	117,252,000	110,984,000
Less: Patronage exclusion	(117,252,000)	$ (110,984,000)
Net operating loss carryforwards	$ 447,086,000

Leases - Summary (Details)

Leases - Summary (Details)	12 Months Ended
	Dec. 31, 2022 lease
Minimum
Lease Disclosure [Line Items]
Finance lease, renewal term	1 year
Maximum
Lease Disclosure [Line Items]
Finance lease, renewal term	5 years
Lease terms through December 31, 2027
Lease Disclosure [Line Items]
Number of finance leases	3
Lease terms through June 30, 2031
Lease Disclosure [Line Items]
Number of finance leases	1
Lease terms through February 2042
Lease Disclosure [Line Items]
Operating lease, renewal term	20 years
Scherer Unit No. 2
Lease Disclosure [Line Items]
Percentage of undivided interest	60%

Leases - Balance sheet impact (

Leases - Balance sheet impact (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Right-of-use assets - Finance leases
Right-of-use assets	$ 302,732	$ 302,732
Less: Accumulated provision for depreciation	(272,876)	(267,606)
Total finance lease assets	29,856	35,126
Lease liabilities - Finance leases
Obligations under finance leases	52,937	61,335
Long-term debt and finance leases due within one year	8,398	7,541
Total finance lease liabilities	61,335	68,876
Right-of-use assets - Operating leases
Electric plant in service, net	3,326	2,293
Total operating lease assets	3,326	2,293
Lease liabilities - Operating leases
Capitalization - Other	2,256	1,550
Other current liabilities	1,164	838
Total operating lease liabilities	$ 3,420	$ 2,388
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Right-of-use assets	Right-of-use assets
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List]	In service	In service
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Obligation under Hydro Facility Transactions	Obligation under Hydro Facility Transactions
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other current liabilities	Other current liabilities

Leases - Lease cost (Details)

Leases - Lease cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lease Cost
Amortization of leased assets	$ 7,542	$ 6,420
Interest on lease liabilities	7,408	8,177
Operating lease cost	995	1,079
Total lease cost	$ 15,945	$ 15,676
Weighted-average remaining lease term (in years):
Finance leases	5 years 11 months 8 days	6 years 10 months 24 days
Operating leases	6 years 5 months 8 days	8 years 3 days
Weighted-average discount rate:
Finance leases	11.05%	11.05%
Operating leases	5.52%	4.73%

Leases - Other lease disclosure

Leases - Other lease disclosures (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lessee Disclosure [Abstract]
Operating cash flows from finance leases	$ 7,408	$ 8,177
Operating cash flows from operating leases	1,009	1,129
Financing cash flows from finance leases	7,541	6,772
Right-of-use assets obtained in exchange for new operating lease liabilities	1,954
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	68,876
Operating Leases
2023	1,324
2024	850
2025	641
2026	350
2027	72
Thereafter	868
Total lease payments	4,105
Less: imputed interest	(685)
Total operating lease liabilities	3,420	2,388
Total
2023	16,273
2024	15,799
2025	15,590
2026	15,299
2027	15,021
Thereafter	11,551
Total lease payments	89,533
Less: imputed interest	(24,778)
Present value of lease liabilities	64,755
Lessor Disclosure [Abstract]
Lease income	$ 6,539	$ 6,312
Operating Lease Income Comprehensive Income Extensible List Not Disclosed Flag	Lease income	Lease income

Debt - Maturities for long-term

Debt - Maturities for long-term debt and finance lease obligations and debt outstanding (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Maturities for finance leases
2023	$ 14,949
2024	14,949
2025	14,949
2026	14,949
2027	14,949
Maturities for contractual obligations
2023	322,103
2024	381,753
2025	355,312
2026	336,888
2027	347,035
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts
Principal	11,940,359	$ 10,915,054
Long-term debt
Maturities for long-term debt
2023	313,705
2024	372,402
2025	344,899
2026	325,293
2027	$ 334,123
Maturities for contractual obligations
Weighted average interest rate on long-term debt	3.78%	3.69%
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts
Principal	$ 11,940,359	$ 10,915,054
Unamortized Debt Issuance Costs and Debt Discounts	114,142	111,909
Finance Leases
Maturities for finance leases
2023	8,398
2024	9,351
2025	10,413
2026	11,595
2027	12,912
FFB | Long-term debt
Maturities for long-term debt
2023	312,695
2024	308,892
2025	282,399
2026	262,793
2027	271,623
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts
Principal	7,084,148	6,526,858
Unamortized Debt Issuance Costs and Debt Discounts	52,690	55,159
FMBs | Long-term debt
Maturities for long-term debt
2023	1,010
2024	63,510
2025	62,500
2026	62,500
2027	62,500
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts
Principal	4,152,021	3,653,031
Unamortized Debt Issuance Costs and Debt Discounts	52,480	46,985
PCRBs | Long-term debt
Maturities for long-term debt
2023	0
2024	0
2025	0
2026	0
2027	0
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts
Principal	704,190	735,165
Unamortized Debt Issuance Costs and Debt Discounts	$ 8,972	$ 9,765

Debt - Department of Energy Loa

Debt - Department of Energy Loan Guarantee (Details)	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Mar. 22, 2019 USD ($)	Dec. 31, 2018 USD ($)	Feb. 20, 2014 USD ($) item
Debt
Repayments of long-term debt	$ 397,162,000	$ 468,577,000	$ 1,334,368,000
Vogtle Units No. 3 & No. 4
Debt
Guarantee obligations, maximum exposure received					$ 1,104,000,000
Long-term debt | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	4,633,028,088
Long-term debt | FFB
Debt
Number of future advance promissory notes | item						2
Maximum borrowing capacity				$ 1,619,679,706		$ 3,057,069,461
Aggregate borrowings including capitalized interest	1,619,679,706
Maximum borrowing capacity designated for capitalized interest	43,721,079					335,471,604
Eligible project costs, percent				70%
Repayments of long-term debt	$ 307,600,000
Long-term debt | FFB | Maximum
Debt
Aggregate borrowings including capitalized interest						$ 3,057,069,461
Long-term debt | FFB | Department of Energy guarantee | Services Agreement
Debt
Guarantee obligations, maximum exposure received				$ 4,676,749,167
Long-term debt | FFB | US Treasury Securities, Current Yield
Debt
Spread on variable rate (as a percent)	0.375%

Debt - Rural Utilities Service

Debt - Rural Utilities Service Guaranteed Loans (Details) - Long-term debt - FFB - Rural Utilities Service Guaranteed Loans - USD ($) $ in Thousands	1 Months Ended		12 Months Ended
	Jan. 31, 2023	Oct. 31, 2022	Dec. 31, 2022
Debt
Advances received on loans		$ 234,681	$ 317,245
Subsequent Event
Debt
Advances received on loans	$ 15,431

Debt - Credit Facilities (Detai

Debt - Credit Facilities (Details)	Dec. 31, 2022 USD ($) facility
Line of credit | Line of credit
Debt
Maximum borrowing capacity	$ 1,810,000,000
Number of separate facilities | facility	4
Letter of credit
Debt
Maximum borrowing capacity	$ 960,000,000
Available borrowing capacity	957,000,000
Letter of credit | Variable Rate Demand Obligation
Debt
Available borrowing capacity	2,504,000
Commercial paper
Debt
Line of credit, amount outstanding	$ 659,000,000

Debt - First Mortgage Bonds (De

Debt - First Mortgage Bonds (Details) $ in Thousands	Apr. 12, 2022 USD ($)
Debt
Repayments of Commercial Paper	$ 493,405
Mortgage Bonds | Series 2022A First Mortgage Bonds
Debt
Principal amount	$ 500,000
Interest rate (as a percent)	4.50%

Debt - Pollution Control Revenu

Debt - Pollution Control Revenue Bonds (Details) - Municipal bonds - Series 2017 Pollution Control Revenue Bonds - USD ($) $ in Thousands	Sep. 09, 2022	Feb. 01, 2023
Debt
Redemption of bonds	$ 30,975
Subsequent Event
Debt
Principal amount		$ 99,785

Electric plant, construction _3

Electric plant, construction and related agreements - Electric plant (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Public Utility Property Plant and Equipment
Investment	$ 9,569,359	$ 10,168,392
Accumulated Depreciation	(5,183,589)	(5,565,724)
Total construction work in progress	7,716,035	6,779,392
Plant acquisition adjustments	$ 280,396	248,000
Vogtle Units No. 1 & No. 2
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	30%
Investment	$ 3,024,112	3,010,843
Accumulated Depreciation	$ (1,916,942)	(1,881,324)
Vogtle Units No. 3 & No. 4
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	30%
Investment	$ 58,189	58,199
Accumulated Depreciation	(8,627)	(7,290)
Total construction work in progress	$ 7,583,291	6,680,014
Hatch Units No. 1 & No. 2
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	30%
Investment	$ 991,852	973,682
Accumulated Depreciation	$ (533,771)	(503,871)
Wansley Units No. 1 & No. 2
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	30%
Investment	$ 20,312	820,110
Accumulated Depreciation	$ (15,337)	(649,301)
Scherer Unit No. 1
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	60%
Investment	$ 1,378,904	1,415,115
Accumulated Depreciation	$ (636,799)	(638,443)
Doyle
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 145,780	144,711
Accumulated Depreciation	$ (124,306)	(120,527)
Rocky Mountain Units No. 1, No. 2 & No. 3
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	75%
Investment	$ 616,278	615,485
Accumulated Depreciation	$ (296,624)	(284,749)
Hartwell
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 232,532	227,834
Accumulated Depreciation	$ (125,092)	(121,174)
Hawk Road Energy Facility
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 269,837	266,149
Accumulated Depreciation	$ (74,685)	(69,194)
Talbot
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 301,869	300,335
Accumulated Depreciation	$ (162,137)	(158,270)
Chattahoochee
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 324,310	319,550
Accumulated Depreciation	$ (171,272)	(166,859)
Effingham
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 339,189	337,614
Accumulated Depreciation	$ (121,318)	(112,057)
Smith Energy Facility
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 686,517	672,184
Accumulated Depreciation	$ (208,142)	(190,760)
Wansley
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	30%
Investment		3,942
Accumulated Depreciation		(3,889)
Washington County
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	100%
Investment	$ 170,432
Accumulated Depreciation	(88,585)
Transmission
Public Utility Property Plant and Equipment
Investment	107,992	102,966
Accumulated Depreciation	(64,785)	(62,457)
Other production
Public Utility Property Plant and Equipment
Investment	106,424	104,372
Accumulated Depreciation	$ (65,922)	(62,885)
Scherer Unit No. 2
Public Utility Property Plant and Equipment
Ownership interest (as a percent)	60%
Investment	$ 794,830	795,301
Accumulated Depreciation	(569,245)	(532,674)
Environmental and other generation improvements
Public Utility Property Plant and Equipment
Total construction work in progress	$ 132,744	$ 99,378

Electric plant, construction _4

Electric plant, construction and related agreements - Narrative (Details) $ in Millions		12 Months Ended
	Feb. 18, 2019 USD ($)	Dec. 31, 2022 USD ($) item MW	Dec. 31, 2008 item 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		$ 8,000
Ownership interest (as a percent)		30%
Monthly delay cost, exercise of tender option		$ 30
Remaining share paid by counterparty upon exercise of tender option (as a percent)		100%
Budget increases since the nineteenth VCM				$ 3,400
Percentage of disallowed costs excluded from adverse event triggers		6%
Vogtle Units No. 3 & No. 4 | Jointly Owned Nuclear Power Plant
Public Utility Property Plant and Equipment
Release of generating capacity with exercise of tender option (in megawatts) | MW		55
Proportionate ownership share with exercise of tender option (as a percent)		27.50%
Total project cost		$ 8,100
Vogtle Units No. 3 & No. 4 | Financial Exposure Term One
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30%
Vogtle Units No. 3 & No. 4 | Financial Exposure Term Two
Public Utility Property Plant and Equipment
Ownership interest (as a percent)		30%
Vogtle Units No. 3 & No. 4 | Minimum
Public Utility Property Plant and Equipment
COVID related costs		$ 350
Vogtle Units No. 3 & No. 4 | Maximum
Public Utility Property Plant and Equipment
COVID related costs		$ 438
Vogtle Units No. 3 & No. 4 | EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Public Utility Property Plant and Equipment
Number of nuclear units | item		2	2
Generating capacity (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		$ 8,650
Ownership share, generating capacity (in megawatts) | MW		660
Construction cost savings due to exercise of tender option		$ 530
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		8,650
Total project cost		18,380
Increase in project budget based on Georgia Power's interpretation		$ 530
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 Unit Number 4
Public Utility Property Plant and Equipment
Monthly delay cost, exercise of tender option		$ 13

Electric plant, construction _5

Electric plant, construction and related agreements - Project Budget and Actual Costs (Details) - Vogtle Units No. 3 & No. 4 $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Actual Costs at December 31, 2022
Proceeds from guarantee agreement	$ 1,100
Capital costs	2,100
Cost sharing benefits	99
Jointly Owned Nuclear Power Plant
Project Budget (Tender)
Construction Costs	6,554
Freeze Capital Credit	(528)
Financing Costs	2,025
Subtotal	8,051
Deferred Training Costs	47
Total Project Costs Before Contingency	8,098
Oglethorpe Contingency	2
Totals	8,100
Actual Costs at December 31, 2022
Construction Costs	6,147
Financing Costs	1,770
Subtotal	7,917
Deferred Training Costs	46
Total Project Costs Before Contingency	7,963
Totals	$ 7,963

Employee benefit plans (Details

Employee benefit plans (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($) plan	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
401(k) plan
Maximum percentage of eligible annual compensation that the employee can contribute subject to IRS limitations	60%
Employer matching contribution, as a percent of employee's eligible compensation	6%
Amount of contributions to the matching feature of the 401(k) plan	$ 2,017	$ 1,811	$ 1,716
Contribution to employer retirement contribution feature (as a percent)	11%
Amount of contributions to the employer retirement contribution feature of the 401(k) plan	$ 5,098	4,527	$ 4,371
Deferred compensation plans
Number of deferred compensation plans | plan	2
Deferred compensation liability	$ 4,616	$ 5,840

Nuclear insurance (Details)

Nuclear insurance (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) item
Nuclear insurance:
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Act	$ 13,700
Maximum insurance coverage provided by American Nuclear Insurers to each nuclear plant	450
Maximum amount that a company could be assessed per incident for each licensed reactor	138
Maximum aggregate amount that a reactor can assess in a calendar period for each incident	$ 20
Number of nuclear reactors in which entity has ownership interest | item	5
Maximum deferred premium amount which the entity could be assessed per incident on the basis of its joint ownership interest in four nuclear reactors	$ 206
Maximum deferred premium amount which the entity could be assessed per calendar year on the basis of its joint ownership interest in four nuclear reactors	$ 31
Period considered for inflation adjustment for maximum assessment per reactor and maximum yearly assessment	5 years
Maximum property damage insurance provided to nuclear generating facilities	$ 1,500
Additional coverage provided for losses in excess of primary coverage	$ 1,250
Deductible waiting period	182 days
Additional coverage for additional costs incurred in obtaining replacement power during a prolonged accidental outage	$ 490
Sublimit for non-nuclear losses	750
Maximum limits for accidental property damage occurring during construction under the policy	2,750
Portion of the current maximum annual assessment for Georgia Power that would be payable by the entity based on ownership share	41
Aggregate payment for claims resulting from terrorist acts in one year period	3,200
Aggregate payment for claims resulting from cyber events in one year period	$ 3,200

Commitments (Details)

Commitments (Details)	12 Months Ended
	Dec. 31, 2022 USD ($)
Finance and Operating Leases
2023	$ 16,273,000
2024	15,799,000
2025	15,590,000
2026	15,299,000
2027	15,021,000
Thereafter	$ 11,551,000
Scherer Unit No. 2
Long-term Purchase Commitment [Line Items]
Ownership interest (as a percent)	60%
Coal
Long-term Purchase Commitment [Line Items]
2023	$ 26,891,000
2024	26,070,000
2025	10,426,000
Nuclear Fuel
Long-term Purchase Commitment [Line Items]
2023	78,780,000
2024	39,690,000
2025	32,280,000
2026	28,980,000
2027	26,580,000
Thereafter	67,170,000
Gas Transportation
Long-term Purchase Commitment [Line Items]
2023	63,850,000
2024	62,818,000
2025	62,775,000
2026	68,872,000
2027	67,188,000
Thereafter	824,627,000
Maintenance Agreements
Long-term Purchase Commitment [Line Items]
Cancellation obligation	96,796,000
2023	29,720,000
2024	57,749,000
2025	43,025,000
2026	15,736,000
2027	3,237,000
Thereafter	316,160,000
Asset Retirement Obligations
Long-term Purchase Commitment [Line Items]
2023	16,709,000
2024	52,003,000
2025	46,128,000
2026	49,445,000
2027	67,384,000
Thereafter	$ 3,416,582,000

Contingencies and Regulatory _2

Contingencies and Regulatory Matters (Details)	12 Months Ended
	Dec. 31, 2022 plaintiff
Contingencies and Regulatory Matters:
Number of plaintiffs	7

Plant Wansley (Details)

Plant Wansley (Details) - USD ($)	Dec. 31, 2022	Sep. 30, 2022	Jul. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation [Line Items]
Cost to close plant	$ 1,343,743,000			$ 1,287,143,000	$ 1,135,983,000
Plant Wansley
Asset Retirement Obligation [Line Items]
Ownership interest (as a percent)			30%
Cost to close plant		$ 40,656,000

Plant Acquisition - Narrative (

Plant Acquisition - Narrative (Details) - Washington County Power	Dec. 20, 2022 USD ($) item MW
Plant Acquisition [Line Items]
Number of generating units acquried | item	2
Gulf Pacific Power, LLC
Plant Acquisition [Line Items]
Generating capacity (in megawatts) | MW	660
Natural Gas Processing Plant
Plant Acquisition [Line Items]
Generating capacity (in megawatts) | MW	300
Purchase price of acquisition | $	$ 86,826,000
Transaction costs | $	$ 1,051,000

Plant Acquisition - Identifiabl

Plant Acquisition - Identifiable Assets Acquired and Liabilities Assumed (Details) - Washington County Power - Natural Gas Processing Plant $ in Thousands	Dec. 31, 2022 USD ($)
Plant Acquisition [Line Items]
Electric plant in service, net	$ 80,878
Inventories, at average cost	981
Other current assets	417
Power purchase and sale agreement	(4,708)
Other current liabilities	(158)
Total identifiable net assets	$ 86,826

Quarterly financial data (una_3

Quarterly financial data (unaudited) (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2022	Sep. 30, 2022	Jun. 30, 2022	Mar. 31, 2022	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Quarterly Financial Data [Abstract]
Operating revenues	$ 472,302	$ 704,265	$ 533,128	$ 420,442	$ 409,583	$ 460,822	$ 358,127	$ 376,331
Operating margin	17,384	64,553	54,269	57,845	30,748	46,025	53,035	64,573	$ 194,051	$ 194,381	$ 217,709
Net margin	$ (10,540)	$ 32,097	$ 18,167	$ 21,980	$ 9,771	$ 8,907	$ 13,145	$ 25,958