Cover Page
Cover Page | 12 Months Ended |
Dec. 31, 2023 | |
Cover [Abstract] | |
Document Type | S-4 |
Entity Registrant Name | OGLETHORPE POWER CORP |
Entity Incorporation, State or Country Code | GA |
Entity Tax Identification Number | 58-1211925 |
Entity Address, Address Line One | 2100 East Exchange Place |
Entity Address, City or Town | Tucker |
Entity Address, State or Province | GA |
Entity Address, Postal Zip Code | 30084-5336 |
City Area Code | 770 |
Local Phone Number | 270-7600 |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Entity Central Index Key | 0000788816 |
Amendment Flag | false |
Document Fiscal Year Focus | 2023 |
Document Fiscal Period Focus | FY |
CONSOLIDATED STATEMENTS OF REVE
CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating revenues: | |||
Operating revenues | $ 1,740,185 | $ 2,130,137 | $ 1,604,863 |
Operating expenses: | |||
Fuel | 578,794 | 1,045,089 | 598,996 |
Production | 413,312 | 468,754 | 410,708 |
Depreciation and amortization | 330,449 | 283,774 | 275,346 |
Purchased power | 74,657 | 82,516 | 69,346 |
Accretion | 65,907 | 55,953 | 56,086 |
Total operating expenses | 1,463,119 | 1,936,086 | 1,410,482 |
Operating margin | 277,066 | 194,051 | 194,381 |
Other income: | |||
Investment income | 70,252 | 57,564 | 45,932 |
Amortization of deferred gains | 1,789 | 1,789 | 1,789 |
Allowance for equity funds used during construction | 750 | 700 | 385 |
Other | 8,258 | 12,191 | 23,148 |
Total other income | 81,049 | 72,244 | 71,254 |
Interest charges: | |||
Interest expense | 515,862 | 455,474 | 417,722 |
Allowance for debt funds used during construction | (234,090) | (262,573) | (221,463) |
Amortization of debt discount and expense | 10,553 | 11,690 | 11,595 |
Net interest charges | 292,325 | 204,591 | 207,854 |
Net margin | 65,790 | 61,704 | 57,781 |
Sales to members | |||
Operating revenues: | |||
Operating revenues | 1,681,566 | 1,974,683 | 1,557,109 |
Sales to non-members | |||
Operating revenues: | |||
Operating revenues | $ 58,619 | $ 155,454 | $ 47,754 |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Electric plant: | ||
In service | $ 14,112,098 | $ 9,266,627 |
Right-of-use assets--finance leases | 302,732 | 302,732 |
Less: Accumulated provision for depreciation | (5,418,738) | (5,183,589) |
Electric plant in service, net | 8,996,092 | 4,385,770 |
Nuclear fuel, at amortized cost | 389,662 | 388,303 |
Construction work in progress | 3,294,641 | 7,716,035 |
Total electric plant | 12,680,395 | 12,490,108 |
Investments and funds: | ||
Nuclear decommissioning trust fund | 641,239 | 540,716 |
Investment in associated companies | 82,133 | 78,937 |
Long-term investments | 690,732 | 669,479 |
Other | 35,585 | 32,561 |
Total investments and funds | 1,449,689 | 1,321,693 |
Current assets: | ||
Cash and cash equivalents | 490,592 | 595,381 |
Restricted cash and short-term investments | 0 | 104,431 |
Short-term investments | 143,931 | 61,702 |
Receivables | 201,784 | 220,015 |
Inventories, at weighted average cost | 337,045 | 297,951 |
Prepayments and other current assets | 18,335 | 51,409 |
Total current assets | 1,191,687 | 1,330,889 |
Deferred charges and other assets: | ||
Regulatory assets | 1,131,489 | 1,212,305 |
Prepayments to Georgia Power Company | 13,722 | 20,873 |
Other | 57,869 | 113,502 |
Total deferred charges | 1,203,080 | 1,346,680 |
Total assets | 16,524,851 | 16,489,370 |
Capitalization: | ||
Patronage capital and membership fees | 1,257,917 | 1,192,127 |
Long-term debt | 11,600,917 | 11,512,513 |
Obligations under finance leases | 43,586 | 52,937 |
Obligation under Rocky Mountain transactions | 29,862 | 27,945 |
Other | 5,152 | 2,256 |
Total capitalization | 12,937,434 | 12,787,778 |
Current liabilities: | ||
Long-term debt and finance leases due within one year | 384,426 | 322,102 |
Short-term borrowings | 607,885 | 655,650 |
Accounts payable | 117,272 | 203,705 |
Accrued interest | 106,355 | 105,452 |
Member power bill prepayments, current | 31,406 | 54,443 |
Other current liabilities | 111,109 | 153,941 |
Total current liabilities | 1,358,453 | 1,495,293 |
Deferred credits and other liabilities: | ||
Asset retirement obligations | 1,458,937 | 1,343,743 |
Member power bill prepayments, non-current | 47,133 | 53,877 |
Regulatory liabilities | 706,320 | 792,190 |
Other | 16,574 | 16,489 |
Total deferred credits and other liabilities | 2,228,964 | 2,206,299 |
Total equity and liabilities | 16,524,851 | 16,489,370 |
Commitments and Contingencies (Notes 1, 7, 10, 11 and 12) |
CONSOLIDATED STATEMENTS OF CAPI
CONSOLIDATED STATEMENTS OF CAPITALIZATION - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Secured Long-term debt: | ||
Total Secured Long-term debt | $ 12,096,552 | $ 11,940,359 |
Obligations under finance leases | 52,937 | 61,335 |
Obligation under Rocky Mountain transactions | 29,862 | 27,945 |
Other | 5,152 | 2,256 |
Patronage capital and membership fees | 1,257,917 | 1,192,127 |
Subtotal | 13,442,420 | 13,224,022 |
Less: long-term debt and finance leases due within one year | (384,426) | (322,102) |
Less: unamortized debt issuance costs | (97,850) | (96,588) |
Less: unamortized bond discounts on long-term debt | (22,710) | (17,554) |
Total capitalization | 12,937,434 | 12,787,778 |
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 3.38% at December 31, 2023) due in quarterly installments through 2048 | ||
Secured Long-term debt: | ||
Secured Long-term debt | $ 2,663,385 | 2,758,753 |
Interest rate, average rate (as a percent) | 3.38% | |
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 3.38% at December 31, 2023) 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 3.38% at December 31, 2023) 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, 2023) due in quarterly installments through 2044 | ||
Secured Long-term debt: | ||
Secured Long-term debt | $ 4,177,967 | 4,325,395 |
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, 2023) 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, 2023) 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: | ||
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: | ||
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: | ||
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: | ||
Secured Long-term debt | $ 1,010 | 2,021 |
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: | ||
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: | ||
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: | ||
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: | ||
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: | ||
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: | ||
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: | ||
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: | ||
Secured Long-term debt | $ 500,000 | 500,000 |
Interest rate (as a percent) | 4.50% | |
Public | First mortgage bonds payable: Series 2022A First Mortgage Bonds 6.20% due 2053 | ||
Secured Long-term debt: | ||
Secured Long-term debt | $ 400,000 | 0 |
Interest rate (as a percent) | 6.20% | |
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: | ||
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: | ||
Secured Long-term debt | $ 91,645 | 91,645 |
Interest rate (as a percent) | 4.82% | |
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: | ||
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: | ||
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: Series2017F Burke indexed put bonds-weekly reset, 5.07% due 2040 through 2045 | ||
Secured Long-term debt: | ||
Secured Long-term debt | $ 99,785 | $ 99,785 |
Interest rate (as a percent) | 5.07% |
CONSOLIDATED STATEMENTS OF CA_2
CONSOLIDATED STATEMENTS OF CAPITALIZATION (Parenthetical) | Dec. 31, 2023 |
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 3.38% at December 31, 2023) due in quarterly installments through 2048 | |
Secured Long-term debt: | |
Interest rate, average rate (as a percent) | 3.38% |
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 3.38% at December 31, 2023) 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 3.38% at December 31, 2023) 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, 2023) 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, 2023) 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, 2023) 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) | 4.82% |
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: Series2017F Burke indexed put bonds-weekly reset, 5.07% due 2040 through 2045 | |
Secured Long-term debt: | |
Interest rate (as a percent) | 5.07% |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Cash flows from operating activities: | |||
Net Income (Loss) | $ 65,790 | $ 61,704 | $ 57,781 |
Adjustments to reconcile net margin to net cash provided by operating activities: | |||
Depreciation and amortization, including nuclear fuel | 441,926 | 451,899 | 400,681 |
Accretion cost | 65,907 | 55,953 | 56,086 |
Amortization of deferred gains | (1,789) | (1,789) | (1,789) |
Allowance for equity funds used during construction | (750) | (700) | (385) |
Deferred outage costs | (32,390) | (30,926) | (30,746) |
(Gain) loss on sale of investments | (6,954) | 21,950 | (13,516) |
Gain on sale of spare parts | 0 | 0 | (15,734) |
Regulatory deferral of costs associated with nuclear decommissioning | (21,449) | (54,529) | (19,318) |
Other | (5,150) | (712) | (2,528) |
Change in operating assets and liabilities: | |||
Receivables | 12,011 | (68,550) | (5,693) |
Inventories | (38,562) | (36,235) | 23,232 |
Prepayments and other current assets | (2,211) | 25,031 | 577 |
Accounts payable | (104,164) | 7,008 | 31,790 |
Accrued interest | 903 | 9,042 | 23,976 |
Accrued taxes | 1,087 | 52,764 | (36,301) |
Other current liabilities | (65,795) | 32,300 | (14,292) |
Rate management program (billing credits applied) collections, net | (56,612) | 19,847 | 144,763 |
Other | (57,281) | 2,217 | (38,078) |
Total adjustments | 128,727 | 484,570 | 502,725 |
Net cash provided by operating activities | 194,517 | 546,274 | 560,506 |
Cash flows from investing activities: | |||
Property additions | (474,952) | (1,156,383) | (1,203,050) |
Plant acquisition | (16,743) | (86,826) | (233,156) |
Activity in nuclear decommissioning trust fund – Purchases | (535,027) | (204,500) | (675,153) |
Activity in nuclear decommissioning trust fund - Proceeds | 520,986 | 194,046 | 667,344 |
Proceeds from the sale of spare parts | 0 | 0 | 18,500 |
Decrease in restricted investments | 74,031 | 246,022 | 167,535 |
Activity in other long-term investments – Purchases | (262,712) | (185,092) | (433,532) |
Activity in other long-term investments - Proceeds | 199,200 | 107,082 | 246,256 |
Other | 13,782 | 4,040 | 14,843 |
Net cash used in investing activities | (481,435) | (1,081,611) | (1,430,413) |
Cash flows from financing activities: | |||
Long-term debt proceeds | 506,272 | 1,414,925 | 757,032 |
Long-term debt payments | (358,477) | (397,162) | (468,577) |
(Decrease) increase in short-term borrowings, net | (47,765) | (440,321) | 712,473 |
Other | 51,699 | 2,526 | 44,618 |
Net cash provided by financing activities | 151,729 | 579,968 | 1,045,546 |
Net (decrease) increase in cash, cash equivalents and restricted cash | (135,189) | 44,631 | 175,639 |
Cash, cash equivalents and restricted cash at beginning of period | 625,781 | 581,150 | 405,511 |
Cash, cash equivalents and restricted cash at end of period | 490,592 | 625,781 | 581,150 |
Cash paid for – | |||
Interest (net of amounts capitalized) | 278,952 | 182,066 | 170,605 |
Supplemental disclosure of non-cash investing and financing activities: | |||
Change in asset retirement obligations | 63,803 | 10,486 | 107,677 |
Accrued property additions at end of period | $ 39,854 | $ 65,686 | $ 89,640 |
CONSOLIDATED STATEMENTS OF PATR
CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Increase (Decrease) in Members' Capital | |||
Net margin | $ 65,790 | $ 61,704 | $ 57,781 |
Patronage Capital and Membership Fees | |||
Increase (Decrease) in Members' Capital | |||
Beginning balance | 1,192,127 | 1,130,423 | 1,072,642 |
Net margin | 65,790 | 61,704 | 57,781 |
Ending balance | $ 1,257,917 | $ 1,192,127 | $ 1,130,423 |
Summary of significant accounti
Summary of significant accounting policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Summary of significant accounting policies | 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 7,792 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 756 megawatts of capacity, including 724 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. 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. 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, 2023 and 2022 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2023. 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 2023, 2022 and 2021, 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. On November 15, 2023, we and each of our members amended the wholesale power contracts to extend the term from December 31, 2050 to December 31, 2085. These contracts, 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, 2023 and 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. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2023, 2022 and 2021, 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, 2023 and December 31, 2022, we recognized refund liabilities totaling $34,266,000 and $28,471,000, 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: (dollars in thousands) 2023 2022 2021 Capacity revenues $ 1,082,368 $ 984,036 $ 946,662 Energy revenues 599,198 990,647 610,447 Total $ 1,681,566 $ 1,974,683 $ 1,557,109 The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2023, 2022 or 2021: 2023 2022 2021 Jackson EMC 15.1 % 16.0 % 15.2 % GreyStone Power Corporation, an EMC 11.4 % 9.5 % 12.3 % Cobb EMC 8.5 % 10.0 % 8.7 % Receivables from contracts with our members at December 31, 2023 and December 31, 2022 were $170,901,000 and $187,401,000, respectively. Energy revenues from non-members were primarily due from the sale of the BC Smith deferring members' output into the wholesale market. In 2023 and 2022, we recognized capacity revenues from non-members relating to our Washington County acquisition, which we acquired in December 2022. Sales to non-members were as follows: (dollars in thousands) 2023 2022 2021 Energy revenues $ 44,995 $ 155,372 $ 47,754 Capacity revenues 13,624 82 — Total $ 58,619 $ 155,454 $ 47,754 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 2023, 2022 and 2021 were $9,261,000, $14,796,000 and $15,693,000, respectively. The cumulative amount billed since inception of the program totaled $135,693,000. In 2018, we began an additional rate management program that allowed us to recover future expense on a current basis from our members. In general, the program allowed 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. In December 2022, collections from our members ended for this rate management program. Under this program, net billing credits and amounts billed to participating members during 2023, 2022 and 2021 were ($52,378,000), $11,774,000 and $143,000,000 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. As of December 31, 2023, $308,507,000 is our remaining liability to be credited to our members' bills. For additional information regarding our revenue deferral plan, see Note 1q. 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, 2023, 2022 and 2021 were $170,901,000, $187,401,000 and $143,715,000, 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 BC Smith deferring members' output, affiliated companies and investment income. Our receivables from non-members at December 31, 2023 and 2022 were $30,883,000 and $32,614,000, respectively. 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 2023, 2022 and 2021, 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 2023, 2022 and 2021 amounted to $84,192,000, $73,871,000, and $77,366,000, 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, 2023 or December 31, 2022 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. We expect that 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 2020, 2021 and 2023, respectively. The following table reflects the details of the asset retirement obligations included in the consolidated balance sheets for the years 2023 and 2022. (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2022 $ 820,106 $ 461,528 $ 62,109 $ 1,343,743 Liabilities incurred 62,841 — — 62,841 Liabilities settled — (14,445) (76) (14,521) Accretion 46,857 16,558 2,492 65,907 Deferred accretion — 5 — 5 Change in cash flow estimates — 321 641 962 Balance at December 31, 2023 $ 929,804 $ 463,967 $ 65,166 $ 1,458,937 (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2021 $ 778,214 $ 442,686 $ 66,243 $ 1,287,143 Liabilities incurred — — — — 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 Asset Retirement Obligations Nuclear Decommissioning. Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service, as well as the management of spent fuel. We do not have a legal obligation to decommission non-radiated structures and, therefore, these costs are excluded from the related asset retirement obligation and the amounts in the table above. Actual decommissioning costs may vary from these estimates because of, but not limited to, changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Our most recent assessment of the nuclear asset obligation for Plant Hatch and Plant Vogtle Units No. 1 and No. 2, which occurred in 2021 resulted in a slight decrease in the obligation for nuclear decommissioning. On March 6, 2023 and February 14, 2024, Plant Vogtle Units No. 3's and No. 4's nuclear reactors achieved self-sustaining nuclear fission, commonly referred to as initial criticality. As a result, in March 2023, we recognized a new nuclear asset retirement obligation totaling $62,841,000 for Plant Vogtle Unit No. 3. We expect to record an asset retirement obligation of approximately $65,000,000 for Plant Vogtle Unit No. 4 in the first quarter of 2024. Our portion of the estimated costs of decommissioning co-owned nuclear facilities for which we have recorded asset retirement obligations as of December 31, 2023 are as follows: (dollars in thousands) 2021 site study Hatch Hatch Vogtle Vogtle Expected start date of decommissioning 2034 2038 2047 2049 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 (dollars in thousands) 2020 site study Vogtle Expected start date of decommissioning 2061 Estimated costs based on site study in 2020 dollars: Radiated structures $ 187,000 Spent fuel management 19,000 Non-radiated structures 22,000 Total estimated site study costs $ 228,000 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. Coal combustion residuals (CCR) are subject to Federal and State regulations. Our obligations associated with CCR are primarily for the closure of coal ash ponds. During 2023 and 2022, assessments of the coal ash pond asset retirement obligation resulted in a $321,000 increase and a $16,301,000 increase in cash flow estimates for coal ash decommissioning, respectively. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR regulations. The 2022 increase in cash flow estimates was primarily due to the Georgia Public Service Commission's approval of Georgia Power's request to revise the closure of the Plant Wansley coal ash pond from in-place to removal. Additional adjustments to the asset retirement obligations are expected periodically due to potential changes in estimates and assumptions. We have internally segregated the funds collected for coal ash pond and other CCR decommissioning costs, including earnings thereon. As of December 31, 2023 and December 31, 2022, the fund balances were $176,630,000 and $153,208,000, 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. As a result of nuclear fuel load for Plant Vogtle Units No. 3 and No. 4, in 2023 and 2022, we contributed $4,619,000 and $2,643,000, respectively, 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. We contributed $10,000,000 and $8,350,000 into the internal funds.in 2023 and 2022, respectively. The following table outlines the fair value of our nuclear decommissioning funds as of December 31, 2023 and December 31, 2022. The funds were invested in a diversified mix of approximately 71% equity and 29% fixed income securities in 2023 and 69% equity and 31% fixed income securities in 2022. 2023 External Trust Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Gain(Loss) Fair Value 12/31/2023 Equity $ 228,936 $ 29,307 $ (9,180) $ 201,900 $ 450,963 Debt 192,986 485,705 (482,935) (4,751) 191,005 Other 91 20,015 (20,835) — (729) $ 422,013 $ 535,027 $ (512,950) $ 197,149 $ 641,239 __________________ (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $22,078,000. 2023 Internal Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value Equity $ 79,122 $ — $ 7,256 $ 39,134 $ 125,512 Debt 43,032 59,630 (53,342) (942) 48,378 $ 122,154 $ 59,630 $ (46,086) $ 38,192 $ 173,890 __________________ (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $13,542,000. 2022 External Trust Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value 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: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value 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. 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 6.2% in the last ten years and 6.0% since inception in 1990. 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 2023, 2022, and 2021 were as follows: Remaining Useful Life Range in years * 2023 2022 2021 Steam production 19-21 3.05 % 13.77 % 14.47 % Nuclear production 11-59 1.87 % 2.17 % 2.18 % Hydro production 43 2.00 % 2.00 % 2.00 % Other production 16-30 2.73 % 2.68 % 2.60 % Transmission 11-59 2.75 % 2.75 % 2.75 % General 1-42 2.00-33.33% 2.00-33.33% 2.00-33.33% __________________ * Based on estimated retirement dates as of 2023. 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 2023, 2022 and 2021 was $321,047,000, $278,452,000, and $269,280,000 |
Fair Value
Fair Value | 12 Months Ended |
Dec. 31, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value | Fair Value: Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: • Level 1 . Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded. • Level 2 . Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs. • Level 3 . Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. 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 December 31, 2023 Quoted Prices in Significant Other Significant (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 234,979 $ 234,979 $ — $ — International equity trust $ 134,911 — 134,911 — Corporate bonds and debt $ 67,986 — 67,900 86 US Treasury securities $ 43,917 43,917 — — Mortgage backed securities $ 58,763 — 58,763 — Domestic mutual funds $ 85,481 85,481 — — Municipal bonds $ 303 — 303 — Federal agency securities $ 7,256 — 7,256 — Non-US Gov't bonds & private placements $ 2,717 — 2,717 — International mutual funds $ 2,012 — 2,012 — Other $ 2,914 2,914 — — Long-term investments: International equity trust $ 43,202 — 43,202 — Corporate bonds and debt $ 14,151 — 14,151 — US Treasury securities $ 17,243 17,243 — — Mortgage backed securities $ 15,024 — 15,024 — Domestic mutual funds $ 378,387 378,387 — — Treasury STRIPS $ 220,765 — 220,765 — Non-US Gov't bonds & private placements $ 1,568 — 1,568 — Other $ 392 392 — — Short-term investments: Treasury STRIPS $ 143,931 — 143,931 — Natural gas swaps $ 13,445 — 13,445 — Fair Value Measurements at Reporting Date Using December 31, 2022 Quoted Prices in Significant Other Significant (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 204,129 $ 204,129 $ — $ — International equity trust $ 111,266 — 111,266 — Corporate bonds and debt $ 60,806 — 60,788 18 US Treasury securities $ 49,775 49,775 — — Mortgage backed securities $ 41,210 — 41,210 — Domestic mutual funds $ 57,348 57,348 — — Federal agency securities $ 2,037 — 2,037 — Non-US Gov't bonds & private placements $ 2,890 — 2,890 — International mutual funds $ 653 653 Other $ 10,602 10,602 — — Long-term investments: International equity trust $ 33,606 — 33,606 — Corporate bonds and debt $ 10,473 — 10,473 — US Treasury securities $ 15,488 15,488 — — Mortgage backed securities $ 12,113 — 12,113 — Domestic mutual funds $ 302,302 302,302 — — Treasury STRIPS $ 293,281 — 293,281 — Non-US Gov't bonds & private placements $ 1,976 — 1,976 — Other $ 240 240 — — Short-term investments: Treasury STRIPS $ 61,702 61,702 Natural gas swaps $ 131,804 — 131,804 — The Level 2 investments above in corporate bonds and debt, federal agency 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, 2023 and 2022 were as follows: 2023 2022 (in thousands) Carrying Fair Carrying Fair Long-term debt $ 12,096,552 $ 10,638,749 $ 11,940,359 $ 10,194,954 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, 2023 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. |
Derivative instruments
Derivative instruments | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative instruments | 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, 2023 all of the counterparties with transaction amounts outstanding under our derivative programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade. We have entered into International Swaps and Derivatives Association agreements with our natural gas derivative counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement). Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions. The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. At December 31, 2023 and 2022, the estimated fair values of our natural gas contracts were net assets of $13,445,000 and $131,804,000, respectively. As of December 31, 2023, none of our counterpa rties were required to post credit collateral u nder our natural gas swap agreements. As of December 31, 2022, one of our counterpa rties was required to post credit collateral totali ng $30,400,000 u nder our natural gas swap agreements. Such posted collateral was classified as restricted cash and included in the Restricted cash and short-term investments line item within our consolidated balance sheets. The following table reflects the volume activity of our natural gas derivatives as of December 31, 2023 that is expected to settle or mature each year: Year Natural Gas (in millions) 2024 32.4 2025 25.1 2026 20.9 2027 10.3 2028 — Total 88.7 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, 2023 and 2022. Consolidated Balance Sheet Location Fair Value 2023 2022 (dollars in thousands) Assets Natural gas swaps Other current assets $ — $ 35,285 Natural gas swaps Other deferred charges $ 25,459 $ 99,725 Liabilities Natural gas swaps Other current liabilities $ 10,370 $ 3,206 Natural gas swaps Other deferred credits $ 1,644 $ — The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the years ended December 31, 2023, 2022 and 2021. Consolidated 2023 2022 2021 (dollars in thousands) Natural gas swaps gains Fuel $ 2,001 $ 121,626 $ 31,440 Natural gas swaps losses Fuel (22,924) (6,587) (1,431) Total $ (20,923) $ 115,039 $ 30,009 The following table presents the unrealized (gains) and losses on derivative instruments deferred on the consolidated balance sheets at December 31, 2023 and 2022. Consolidated Balance 2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 13,445 $ 131,804 Total $ 13,445 $ 131,804 |
Investments
Investments | 12 Months Ended |
Dec. 31, 2023 | |
Schedule of Investments [Abstract] | |
Investments | 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, 2023 and 2022. (dollars in thousands) Gross Unrealized 2023 Cost Gains Losses Fair Value Equity $ 344,669 $ 246,795 $ (5,549) $ 585,915 Debt 908,316 3,938 (25,181) 887,073 Other 2,889 61 (36) 2,914 Total $ 1,255,874 $ 250,794 $ (30,766) $ 1,475,902 (dollars in thousands) Gross Unrealized 2022 Cost Gains Losses Fair Value 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 The cost basis of our debt securities that were in unrealized loss positions at December 31, 2023 was $788,798,000. At December 31, 2023, $3,362,000 of the $25,181,000 of unrealized losses relates to securities that have been in unrealized loss positions for less than twelve months and $21,819,000 relates to securities that have been in unrealized loss positions for greater than twelve months. These unrealized losses are primarily attributable to increases in market interest rates. The contractual maturities of debt securities, which are included in the estimated fair value table above, at December 31, 2023 and 2022 are as follows: (dollars in thousands) 2023 2022 Cost Fair Value Cost Fair Value Due within one year $ 486,602 $ 477,726 $ 367,199 $ 353,180 Due after one year through five years 267,690 260,193 293,523 275,073 Due after five years through ten years 47,804 47,416 66,255 62,576 Due after ten years 106,220 101,738 106,058 96,209 Total $ 908,316 $ 887,073 $ 833,035 $ 787,038 The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2023, 2022 and 2021: (dollars in thousands) 2023 2022 2021 Gross realized gains $ 15,518 $ 10,029 $ 33,501 Gross realized losses (8,564) (31,979) (19,985) Proceeds from sales 720,186 301,128 913,600 Investment in associated companies Investments in associated companies were as follows at December 31, 2023 and 2022: (dollars in thousands) 2023 2022 National Rural Utilities Cooperative Finance Corporation (CFC) $ 24,068 $ 24,081 CT Parts, LLC 6,568 6,574 Georgia Transmission Corporation 40,806 38,287 Georgia System Operations Corporation 6,500 7,750 Other 4,191 2,245 Total $ 82,133 $ 78,937 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 under six separate leases. RMLC then subleased the undivided interests back to us under six separate leases for an identical term. 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 $13,901,000. 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, 2023 | |
Income Tax Disclosure [Abstract] | |
Income taxes | 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: 2023 2022 2021 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, 2023 and 2022 were as follows: (dollars in thousands) 2023 2022 Deferred tax assets Net operating losses $ 109,447 $ 115,080 Obligation related to asset retirements 375,530 345,879 Advance payments 176,956 183,833 Other regulatory liabilities 23,652 18,687 Other assets 30,085 30,373 Deferred tax assets 715,670 693,852 Less: Valuation allowance — — Net deferred tax assets $ 715,670 $ 693,852 Deferred tax liabilities Fixed assets and intangibles $ (154,219) $ (140,095) Right-of-use assets-finance leases (77,923) (77,923) Other regulatory asset (373,802) (343,230) Other liabilities (15,679) (15,352) Deferred tax liabilities (621,623) (576,600) Net deferred tax assets (liabilities) $ 94,047 $ 117,252 Less: Patronage exclusion (94,047) (117,252) Net deferred taxes $ — $ — As of December 31, 2023, we have federal net operating loss carryforwards of $425,203,000 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 2020 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 2020 and forward. We have no liabilities recorded for uncertain tax positions. |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Leases | Leases: As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during 2023 and 2022 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through November 30, 2028. 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 additional operating leases including one for office equipment that has a term extending through October 31, 2028 and one for real property at one of our electric generating facilities that has a term extending through February 2042 with one renewal option for a 20-year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use 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. We combine lease and nonlease components for all lease agreements. Classification 2023 2022 (dollars in thousands) Right-of-use assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (278,586) (272,876) Total finance lease assets $ 24,146 $ 29,856 Lease liabilities - Finance leases Obligations under finance leases $ 43,586 $ 52,937 Long-term debt and finance leases due within one year 9,351 8,398 Total finance lease liabilities $ 52,937 $ 61,335 Classification 2023 2022 (dollars in thousands) Right-of-use assets - Operating leases Electric plant in service, net $ 6,587 $ 3,326 Total operating lease assets $ 6,587 $ 3,326 Lease liabilities - Operating leases Capitalization - Other $ 5,152 $ 2,256 Other current liabilities 1,529 1,164 Total operating lease liabilities $ 6,681 $ 3,420 2023 2022 (dollars in thousands) Lease Cost Classification Finance lease cost: Amortization of leased assets Depreciation and amortization $ 8,398 $ 7,542 Interest on lease liabilities Interest expense $ 6,551 $ 7,408 Operating lease cost Inventory (1) & production expense $ 1,441 $ 995 Total lease cost $ 16,390 $ 15,945 __________________ (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, 2023 December 31, 2022 Lease Term and Discount Rate Weighted-average remaining lease term (in years): Finance leases 5.26 5.94 Operating leases 5.77 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 6.37 % 5.52 % 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 6,551 $ 7,408 Operating cash flows from operating leases $ 1,410 $ 1,009 Financing cash flows from finance leases $ 8,398 $ 7,541 Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,503 $ 1,954 Maturity analysis of our finance and operating lease liabilities as of December 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2024 $ 14,949 $ 1,913 $ 16,862 2025 14,949 1,703 16,652 2026 14,949 1,412 16,361 2027 14,949 1,134 16,083 2028 3,052 1,026 4,078 Thereafter 7,633 795 8,428 Total lease payments $ 70,481 $ 7,983 $ 78,464 Less: imputed interest (17,544) (1,302) (18,846) Present value of lease liabilities $ 52,937 $ 6,681 $ 59,618 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 2023 and 2022 was as follows: 2023 2022 (dollars in thousands) Lease income $ 6,776 $ 6,539 |
Leases | Leases: As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during 2023 and 2022 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through November 30, 2028. 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 additional operating leases including one for office equipment that has a term extending through October 31, 2028 and one for real property at one of our electric generating facilities that has a term extending through February 2042 with one renewal option for a 20-year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use 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. We combine lease and nonlease components for all lease agreements. Classification 2023 2022 (dollars in thousands) Right-of-use assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (278,586) (272,876) Total finance lease assets $ 24,146 $ 29,856 Lease liabilities - Finance leases Obligations under finance leases $ 43,586 $ 52,937 Long-term debt and finance leases due within one year 9,351 8,398 Total finance lease liabilities $ 52,937 $ 61,335 Classification 2023 2022 (dollars in thousands) Right-of-use assets - Operating leases Electric plant in service, net $ 6,587 $ 3,326 Total operating lease assets $ 6,587 $ 3,326 Lease liabilities - Operating leases Capitalization - Other $ 5,152 $ 2,256 Other current liabilities 1,529 1,164 Total operating lease liabilities $ 6,681 $ 3,420 2023 2022 (dollars in thousands) Lease Cost Classification Finance lease cost: Amortization of leased assets Depreciation and amortization $ 8,398 $ 7,542 Interest on lease liabilities Interest expense $ 6,551 $ 7,408 Operating lease cost Inventory (1) & production expense $ 1,441 $ 995 Total lease cost $ 16,390 $ 15,945 __________________ (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, 2023 December 31, 2022 Lease Term and Discount Rate Weighted-average remaining lease term (in years): Finance leases 5.26 5.94 Operating leases 5.77 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 6.37 % 5.52 % 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 6,551 $ 7,408 Operating cash flows from operating leases $ 1,410 $ 1,009 Financing cash flows from finance leases $ 8,398 $ 7,541 Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,503 $ 1,954 Maturity analysis of our finance and operating lease liabilities as of December 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2024 $ 14,949 $ 1,913 $ 16,862 2025 14,949 1,703 16,652 2026 14,949 1,412 16,361 2027 14,949 1,134 16,083 2028 3,052 1,026 4,078 Thereafter 7,633 795 8,428 Total lease payments $ 70,481 $ 7,983 $ 78,464 Less: imputed interest (17,544) (1,302) (18,846) Present value of lease liabilities $ 52,937 $ 6,681 $ 59,618 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 2023 and 2022 was as follows: 2023 2022 (dollars in thousands) Lease income $ 6,776 $ 6,539 |
Leases | Leases: As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during 2023 and 2022 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through November 30, 2028. 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 additional operating leases including one for office equipment that has a term extending through October 31, 2028 and one for real property at one of our electric generating facilities that has a term extending through February 2042 with one renewal option for a 20-year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use 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. We combine lease and nonlease components for all lease agreements. Classification 2023 2022 (dollars in thousands) Right-of-use assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (278,586) (272,876) Total finance lease assets $ 24,146 $ 29,856 Lease liabilities - Finance leases Obligations under finance leases $ 43,586 $ 52,937 Long-term debt and finance leases due within one year 9,351 8,398 Total finance lease liabilities $ 52,937 $ 61,335 Classification 2023 2022 (dollars in thousands) Right-of-use assets - Operating leases Electric plant in service, net $ 6,587 $ 3,326 Total operating lease assets $ 6,587 $ 3,326 Lease liabilities - Operating leases Capitalization - Other $ 5,152 $ 2,256 Other current liabilities 1,529 1,164 Total operating lease liabilities $ 6,681 $ 3,420 2023 2022 (dollars in thousands) Lease Cost Classification Finance lease cost: Amortization of leased assets Depreciation and amortization $ 8,398 $ 7,542 Interest on lease liabilities Interest expense $ 6,551 $ 7,408 Operating lease cost Inventory (1) & production expense $ 1,441 $ 995 Total lease cost $ 16,390 $ 15,945 __________________ (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, 2023 December 31, 2022 Lease Term and Discount Rate Weighted-average remaining lease term (in years): Finance leases 5.26 5.94 Operating leases 5.77 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 6.37 % 5.52 % 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 6,551 $ 7,408 Operating cash flows from operating leases $ 1,410 $ 1,009 Financing cash flows from finance leases $ 8,398 $ 7,541 Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,503 $ 1,954 Maturity analysis of our finance and operating lease liabilities as of December 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2024 $ 14,949 $ 1,913 $ 16,862 2025 14,949 1,703 16,652 2026 14,949 1,412 16,361 2027 14,949 1,134 16,083 2028 3,052 1,026 4,078 Thereafter 7,633 795 8,428 Total lease payments $ 70,481 $ 7,983 $ 78,464 Less: imputed interest (17,544) (1,302) (18,846) Present value of lease liabilities $ 52,937 $ 6,681 $ 59,618 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 2023 and 2022 was as follows: 2023 2022 (dollars in thousands) Lease income $ 6,776 $ 6,539 |
Debt
Debt | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Debt | 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 2028 are as follows: (dollars in thousands) 2024 2025 2026 2027 2028 FFB $ 311,565 $ 284,714 $ 265,177 $ 242,177 $ 283,089 FMBs 63,510 62,500 62,500 62,500 62,500 PCRBs — — — — — $ 375,075 $ 347,214 $ 327,677 $ 304,677 $ 345,589 Finance Leases 9,351 10,413 11,595 12,912 2,153 Total $ 384,426 $ 357,627 $ 339,272 $ 317,589 $ 347,742 The weighted average interest rate on our long-term debt at December 31, 2023 and 2022 was 3.89% and 3.78%, respectively. The weighted average interest rate on our short-term borrowings at December 31, 2023 and 2022 was 5.72% and 4.84%, respectively. Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts at December 31, 2023 and December 31, 2022 are as follows: 2023 2022 Principal Unamortized Debt Principal Unamortized Debt (dollars in thousands) FFB $ 6,841,352 $ 51,083 $ 7,084,148 $ 52,690 FMBs 4,551,010 60,987 4,152,021 52,480 PCRBs 704,190 8,490 704,190 8,972 $ 12,096,552 $ 120,560 $ 11,940,359 $ 114,142 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 term loan facility (the Facility) under which we borrowed a total of $4,633,028,088. We received our final advance under the Facility in December 2022. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began in February 2020. As of December 31, 2023, we have repaid $455,060,646 of principal on the FFB Notes and the aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled $4,177,967,442. The final maturity date is February 20, 2044. 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 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. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve twelve b) Rural Utilities Service Guaranteed Loans: During 2023, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $70,272,000 for long-term financing of general and environmental improvements at existing plants and the BC Smith acquisition. In February 2024, we received an additional $6,067,000 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, 2023, we had a total of $1,810,000,000 of committed credit arrangements comprised of four separate facilities with maturity dates that range from October 2024 to December 2028. 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, 2023, 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, 2023, we had (i) $2,504,000 under these lines of credit in the form of issued letters of credit and (ii) $611,000,000 dedicated under one of these lines of credit to support a like face value of commercial paper that was outstanding. d) First Mortgage Bonds: On December 5, 2023, we issued $400,000,000 of 6.20% first mortgage bonds, Series 2023A, 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 $390,612,000 of outstanding commercial paper. The bonds are due to mature December 2053 and are secured under our first mortgage indenture. e) 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, 2023 | |
Property, Plant and Equipment [Abstract] | |
Electric plant, construction and related agreements | 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, 2023 and 2022 is as follows: 2023 2022 (dollars in thousands) Plant Investment Accumulated Investment Accumulated In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ 3,035,806 $ (1,948,158) $ 3,024,112 $ (1,916,942) Vogtle Unit No. 3 (Nuclear – 30% ownership) 4,771,526 (43,418) 58,189 (8,627) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) 1,019,809 (559,001) 991,852 (533,771) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) 24,710 (27,152) 20,312 (15,337) Scherer Unit No. 1 (Fossil – 60% ownership) 1,372,241 (660,580) 1,378,904 (636,799) Doyle (Combustion Turbine - 100% ownership) 148,902 (127,378) 145,780 (124,306) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) 618,955 (308,827) 616,278 (296,624) Hartwell (Combustion Turbine - 100% ownership) 233,662 (131,434) 232,532 (125,092) Hawk Road (Combustion Turbine - 100% ownership) 272,416 (79,985) 269,837 (74,685) Talbot (Combustion Turbine - 100% ownership) 308,837 (167,033) 301,869 (162,137) Chattahoochee (Combined cycle - 100% ownership) 343,531 (168,292) 324,310 (171,272) BC Smith (Combined cycle - 100% ownership) 352,005 (126,886) 339,189 (121,318) TA Smith (Combined cycle - 100% ownership) 689,198 (228,997) 686,517 (208,142) Washington County (Combustion Turbine – 100% ownership) 171,034 (92,498) 170,432 (88,585) Baconton (Combustion Turbine – 100% ownership) 32,987 (16,379) — — Transmission plant 122,452 (65,784) 107,992 (64,785) Other 101,061 (60,710) 106,424 (65,922) Property under finance lease: Scherer Unit No. 2 (Fossil – 60% leasehold) 795,698 (606,226) 794,830 (569,245) Total in-service $ 14,414,830 $ (5,418,738) $ 9,569,359 $ (5,183,589) Construction work in progress Vogtle Unit No. 4 $ 3,128,720 $ 7,583,291 Environmental and other generation improvements 165,921 132,744 Total construction work in progress $ 3,294,641 $ 7,716,035 _______________ (1) Amounts include plant acquisition adjustments at December 31, 2023 of $290,725,000 and December 31, 2022 of $280,396,000. (2) Plant Vogtle Unit No. 3 was placed in service on July 31, 2023. 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. 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. On July 31, 2023, Georgia Power placed Unit No. 3 in service. Cost and Schedule Our ownership interest and proportionate share of the cost to construct Vogtle Units No. 3 and No. 4 is 30%, representing approximately 660 megawatts. As of December 31, 2023, our actual costs related to the new Vogtle units were approximately $8.2 billion, net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and approximately $384 million we received from Georgia Power in connection with cost-sharing provisions of the Global Amendments and settlement agreement described below. Our current budget, which includes capital costs and allowance for funds used during construction, is a range of $8.3-8.35 billion and is based on a commercial operation date in the second quarter of 2024 for Unit No. 4 and Georgia Power continuing to pay 66% of our 30% share of the remaining cost of construction pursuant to the settlement agreement described below. Any schedule extension beyond June 2024 for Unit No. 4 is expected to increase our costs by approximately $20 million per month. We and some of our members have implemented various rate management programs to lessen the impact on rates related to the additional Vogtle units. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts for Unit No. 4 on a regular basis to incorporate current information available, particularly in the areas of start-up testing and related test results and engineering support. On May 1, 2023, hot functional testing was completed for Unit No. 4. On July 20, 2023, Southern Nuclear announced that all Unit No. 4 inspections, tests, analyses, and acceptance criteria documentation had been submitted to the Nuclear Regulatory Commission, and, on July 28, 2023, the Nuclear Regulatory Commission published its 103(g) finding that the accepted criteria in the combined license for Unit No. 4 had been met, which allowed nuclear fuel to be loaded and start-up testing to begin. Fuel load was completed on August 19, 2023. On October 6, 2023, Georgia Power announced that during start-up and pre-operational testing for Unit No. 4, Southern Nuclear had identified a motor fault in one of four reactor coolant pumps, which was replaced. With Unit No. 3’s four reactor coolant pumps operating as designed, Southern Nuclear has stated that it believes that the motor fault on the single Unit No. 4 reactor coolant pump is an isolated event. However, any findings related to the root cause analysis of the motor fault on the affected pump could require engineering changes or remediation related to the other Unit No. 3 and Unit No. 4 reactor coolant pumps. On February 1, 2024, Georgia Power announced that during start-up and pre-operational testing for Unit No. 4, Southern Nuclear had identified, and remediated, vibrations associated with certain piping within the cooling system. Considering the remaining pre-operational testing, Georgia Power disclosed that it projects Unit No. 4 will be placed in service during the second quarter 2024. On February 14, 2024, Unit No. 4 achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and on March 1, 2024, the generator successfully synchronized to the power grid and generated electricity for the first time. Meeting the projected in-service date for Unit No. 4 significantly depends on the progression of start-up and pre-operational testing, which may be impacted by equipment or other operational failures. As Unit No. 4 progresses further through testing, ongoing and potential future challenges may also include the management of contractors and vendors, the availability of materials and parts, and/or related cost escalation; the availability of supervisory and technical support resources; and the timeframe and duration of pre-operational testing. New challenges also may continue to arise as Unit No. 4 moves further into testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures or components (some of which are based on new technology that only within the last several years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases. With the receipt of the Nuclear Regulatory Commission’s 103(g) findings for Units No. 3 and No. 4 in August 2022 and July 2023, respectively, the site is subject to the Nuclear Regulatory Commission’s operating reactor oversight process and must meet applicable technical and operational requirements contained in its operating license. Various design and other licensing-based compliance matters may result in additional license amendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs. 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 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further in September 2018 by the Term Sheet that was memorialized in February 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). In February 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 was obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion (EAC) for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's VCM 19 filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs. • Georgia Power was 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 was 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 was revised and exceeded the EAC in VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, had 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. On October 5, 2023, we entered into a settlement agreement with Georgia Power to resolve the litigation regarding the proper interpretation of the cost-sharing and tender provisions of the Global Amendments. Under the terms of the agreement, among other items: • Georgia Power agreed that its total liability with respect to the cost-sharing bands was $99 million, plus $5 million of financing costs related to certain payments made under protest related to the cost-sharing bands. Georgia Power made $37.5 million of cost-sharing payments prior to the settlement date and paid us an additional $66.5 million at the time of the settlement agreement for the remaining balance. • Georgia Power will pay 66% of our 30% share of incremental costs of construction that exceed a total project budget of $19.2 billion as such costs are incurred and with no adjustment for costs related to COVID-19 or any other force majeure event. Based on the current project budget, Georgia Power would pay a total of $346.3 million of our construction costs. Georgia Power paid us $241.2 million at the time of the settlement agreement for construction costs previously paid by us and, based on the current project budget, would make $105.1 million in total payments after the settlement date for remaining construction costs. Georgia Power’s ultimate payments pursuant to this arrangement will depend on the final cost of Vogtle Units No. 3 and No. 4 and may be greater or less than the estimated payments based on the current project budget. • We retracted our tender offer and retained our full 30% ownership interest in Vogtle Units No. 3 and No. 4. 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. On August 30, 2023, Georgia Power filed an application with the Georgia Public Service Commission, which included a public announcement that Georgia Power did not intend to submit for rate recovery an amount that is greater than 6% of costs during any VCM reporting period, which triggered the requirement for a Co-owner vote to continue construction. All of the Co-owners voted to continue construction. The ultimate outcome of these matters cannot be determined at this time. Plant Vogtle Unit No. 3 Commercial Operations On July 31, 2023, Plant Vogtle Unit No. 3 reached commercial operation and was placed in service. The total amount in service related to Unit No. 3, including common facilities, as of December 31, 2023, was approximately $4.8 billion. In 2023, since Plant Vogtle Unit No. 3 was placed in service, we sold to Georgia Power $21.7 million of nuclear production tax credits ("NPTCs"), earned by us pursuant to Section 45J of the Internal Revenue Code and recognized the amount as a credit to the Production expense line item within our consolidated income statements. |
Employee benefit plans
Employee benefit plans | 12 Months Ended |
Dec. 31, 2023 | |
Retirement Benefits [Abstract] | |
Employee benefit plans | 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 $2,143,000, $2,017,000 and $1,811,000 in 2023, 2022 and 2021, 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 $5,655,000, $5,098,000 and $4,527,000 in 2023, 2022 and 2021, 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 $5,723,000 and $4,616,000 in 2023 and 2022, respectively. |
Nuclear insurance
Nuclear insurance | 12 Months Ended |
Dec. 31, 2023 | |
Nuclear insurance: | |
Nuclear insurance | Nuclear insurance: The Price-Anderson Act limits public liability claims that could arise from a single nuclear incident to $16.2 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 $166 million per incident for each licensed reactor operated by it, but not more than $25 million per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in six nuclear reactors, we could be assessed a maximum of $299 million per incident, but not more than $44 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, 2028. 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. We started purchasing this coverage in April 2023. Georgia Power, on behalf of all the co-owners has purchased a builders' risk property insurance policy from NEIL for Vogtle Units No. 4. This policy provides the Vogtle owners up to $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 maximum annual assessment for Oglethorpe based on ownership share, is limited to approximately $55 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, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Commitments | 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 2024 for convenience, our cancellation obligation would be approximately $70,699,000. 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 plant and various other leases of minimal value. For information regarding these leases, see Note 6. As of December 31, 2023, our estimated commitments are as follows: (dollars in thousands) Coal Nuclear Fuel Gas Maintenance Asset Finance and Operating Leases 2024 $ 33,810 $ 95,520 $ 66,186 $ 57,749 $ 51,378 $ 16,862 2025 15,938 36,000 67,368 43,025 39,673 16,652 2026 9,362 32,250 69,578 15,736 45,923 16,361 2027 — 28,800 73,075 3,237 59,885 16,083 2028 — 28,500 68,971 46,964 71,267 4,078 Thereafter — 45,660 835,212 269,196 5,065,526 8,428 |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters | 12 Months Ended |
Dec. 31, 2023 | |
Contingencies and Regulatory Matters: | |
Contingencies and Regulatory Matters | Contingencies and Regulatory Matters: We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined. Environmental Matters As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any proposed or 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 in December 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. In December 2022, the Superior Court of Fulton County granted Georgia Power’s motion to transfer the case to the Superior Court of Monroe County. On May 9, 2023, the Superior Court of Monroe County denied Georgia Power’s motion to dismiss the case for lack of subject matter jurisdiction. On July 27, 2023, the Superior Court of Monroe County denied the remaining motions to dismiss certain claims and plaintiffs that Georgia Power filed at the outset of the case. 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 sought an unspecified amount of monetary damages including punitive damages. After Georgia Power removed each of these cases to the U.S. District Court for the Middle District of Georgia, the plaintiffs voluntarily dismissed their complaints without prejudice in November 2022 and February 2023. On May 12, 2023, the plaintiffs refiled their eight complaints in the Superior Court of Monroe County. Also on May 12, 2023, a new complaint was filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that the construction and operation of Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries. The plaintiff seeks an unspecified amount of monetary damages, including punitive damages. On May 18, 2023, Georgia Power removed all of these cases to the U.S. District Court for the Middle District of Georgia. The plaintiffs are requesting the court remand the cases back to the Superior Court of Monroe County. 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 and on April 17, 2023, we and the other co-owners filed motions to dismiss this 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 Acquisitions
Plant Acquisitions | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Plant Acquisitions | Plant Acquisitions: Baconton Power Facility On May 25, 2023, we acquired one generating unit at the Baconton Power Plant, a four-unit 188 megawatt natural gas-fired combustion turbine facility located near Baconton, Georgia, from Baconton Power, LLC. Our unit has an aggregate summer planning reserve generation capacity of approximately 45 megawatts. Our unit also features dual-fuel capability and can run on diesel fuel that is stored on site. The purchase price was $16,743,000 and the acquisition also included other transaction costs of approximately $746,000 (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. In February 2024, we received a conditional commitment for a Rural Utilities Service-guaranteed loan totaling $17.5 million for the Baconton acquisition and we expect to draw on the loan by the end of 2024. 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 Baconton acquisition: Classification (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: Electric plant in service, net $ 16,450 Other current assets 323 Other current liabilities (30) Total identifiable net assets $ 16,743 Some of our members elected to take service (scheduling members) at the date of acquisition and some members have elected to defer (deferring members) their share of output until on or before January 2026. Prior to the deferring members’ use of Baconton, their share of output is being sold into the wholesale market. Revenues and costs of output associated with scheduling members are recognized in the current period. Residual net results of operations, including related interest costs of deferring members are deferred as a regulatory asset. This regulatory asset will be amortized over the then remaining life of the plant, estimated to be 14 years at January 2026. If a deferring member elects to take service before January 2026, amortization of that member's share of the regulatory asset will begin upon taking service. Walton County Plant On August 22, 2023, we signed a membership interest purchase agreement with Mackinaw Power, LLC to purchase Walton County Power, LLC, owner of the Walton County Power Plant. The Walton facility consists of three natural gas-fired combustion turbine electric generating units with a combined nominal capacity of 465 |
Quarterly financial data (unaud
Quarterly financial data (unaudited) | 12 Months Ended |
Dec. 31, 2023 | |
Quarterly Financial Data [Abstract] | |
Quarterly financial data (unaudited) | Quarterly financial data (unaudited): Summarized quarterly financial information for 2023 and 2022 is as follows: First Second Third Fourth (dollars in thousands) 2023 Operating revenues $ 389,453 $ 389,389 $ 500,776 $ 460,567 Operating margin 57,006 49,987 92,317 77,756 Net margin 24,410 18,414 27,127 (4,161) 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) |
Summary of significant accoun_2
Summary of significant accounting policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Business description | 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 7,792 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 756 megawatts of capacity, including 724 megawatts sourced by solar energy. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. |
Basis of accounting | 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. 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, 2023 and 2022 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2023. 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 | 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 | 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 2023, 2022 and 2021, we achieved a margins for interest ratio of 1.14. |
Revenue recognition and Deferred credits and other liabilities | 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. On November 15, 2023, we and each of our members amended the wholesale power contracts to extend the term from December 31, 2050 to December 31, 2085. These contracts, 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, 2023 and 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. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. 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 2023, 2022 and 2021 were $9,261,000, $14,796,000 and $15,693,000, respectively. The cumulative amount billed since inception of the program totaled $135,693,000. 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 2025. Deferred credits and other liabilities also consists of asset retirement obligations as discussed in Note 1h and regulatory liabilities in Note 1q. |
Receivables | 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, 2023, 2022 and 2021 were $170,901,000, $187,401,000 and $143,715,000, 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 BC Smith deferring members' output, affiliated companies and investment income. Our receivables from non-members at December 31, 2023 and 2022 were $30,883,000 and $32,614,000, respectively. 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 |
Nuclear fuel cost | Nuclear fuel costThe cost of nuclear fuel is amortized to fuel expense based on usage. |
Asset retirement obligations and other retirement costs | 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 2020, 2021 and 2023, respectively. Asset Retirement Obligations Nuclear Decommissioning. 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. Coal combustion residuals (CCR) are subject to Federal and State regulations. Our obligations associated with CCR are primarily for the closure of coal ash ponds. During 2023 and 2022, assessments of the coal ash pond asset retirement obligation resulted in a $321,000 increase and a $16,301,000 increase in cash flow estimates for coal ash decommissioning, respectively. Estimates are based on various assumptions including, but not limited to, closure and post-closure cost estimates, timing of expenditures, escalation factors, discount rates and methods for complying with the CCR regulations. The 2022 increase in cash flow estimates was primarily due to the Georgia Public Service Commission's approval of Georgia Power's request to revise the closure of the Plant Wansley coal ash pond from in-place to removal. Additional adjustments to the asset retirement obligations are expected periodically due to potential changes in estimates and assumptions. We have internally segregated the funds collected for coal ash pond and other CCR decommissioning costs, including earnings thereon. As of December 31, 2023 and December 31, 2022, the fund balances were $176,630,000 and $153,208,000, 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 |
Nuclear decommissioning funds | 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. As a result of nuclear fuel load for Plant Vogtle Units No. 3 and No. 4, in 2023 and 2022, we contributed $4,619,000 and $2,643,000, respectively, 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. 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. |
Depreciation | 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 |
Electric plant | 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 2023, 2022 and 2021, the allowance for funds used during construction rates were 4.18%, 4.03% and 3.90%, 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 | 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 | Restricted cash and investments Restricted short-term investments consisted of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that were held by the U.S. Treasury, acting through the Federal Financing Bank. At December 31, 2022, we had restricted investments totaling $74,031,000, all of which were classified as current. During the three-month period ended March 31, 2023, we utilized all of our restricted investments for scheduled Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. No restricted investments were held at December 31, 2023. |
Inventories | 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. |
Deferred charges and other assets | Deferred charges and other assets Deferred charges and other assets represent regulatory assets, long-term prepayments to Georgia Power Company and other deferred charges. For a discussion regarding regulatory assets, see Note 1q. Other deferred charges primarily represent the fair value of our natural gas contracts that will settle after the next twelve months and other long-term prepayments. |
Regulatory assets and liabilities | Regulatory assets and liabilities We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery 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, 2085. 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. |
Related parties | 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 2023, 2022, and 2021, we incurred expenses from Georgia Transmission of $41,426,000, $40,774,000 and $39,677,000, respectively. |
Other income | 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 | Recently issued or adopted accounting pronouncements In November 2023, the Financial Accounting Standards Board (FASB) issued “Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures.” The amendments in this update are intended to improve reportable segment disclosure requirements, primarily through enhanced disclosures about significant expenses. The amendments in this update require disclosures to include significant segment expenses that are regularly provided to the chief operating decision maker (CODM), a description of other segment items by reportable segment, and any additional measures of a segment's profit or loss used by the CODM when deciding how to allocate resources. The amendments in this update are also applicable to entities with only one reportable segment. The amendments in this update also require all annual disclosures currently required by Topic 280 to be included in interim periods. The new standard is effective for us for annual reporting periods beginning after December 15, 2023 and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted and requires retrospective application to all prior periods presented in the financial statements. We are currently evaluating the future impact of this standard on our consolidated financial statements. In December 2023, the FASB amended "Income Taxes (Topic 740): Improvements to Income Tax Disclosures”. The amendments in this update requires additional disclosures related to the rate reconciliation, income taxes paid and other amendments intended to improve effectiveness and comparability. The amendments in this update are effective for us for annual periods beginning after December 15, 2024. Early adoption is permitted and should be applied on a prospective basis. Retrospective application is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements, however, we do not anticipate the impact will be significant. |
Measurement of credit losses on financial instruments | Measurement of credit losses on financial instruments The financial assets we hold that are subject to credit losses (Topic 326) are predominately accounts receivable and certain cash equivalents classified as held-to-maturity debt (e.g. commercial paper). Our receivables are generally due within thirty days or less with a significant portion related to billings to our members. See Note 1f for information regarding our member receivables. Commercial paper we invest in is rated as investment grade. 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, 2023 | |
Accounting Policies [Abstract] | |
Schedule of sales to members | Sales to members were as follows: (dollars in thousands) 2023 2022 2021 Capacity revenues $ 1,082,368 $ 984,036 $ 946,662 Energy revenues 599,198 990,647 610,447 Total $ 1,681,566 $ 1,974,683 $ 1,557,109 Sales to non-members were as follows: (dollars in thousands) 2023 2022 2021 Energy revenues $ 44,995 $ 155,372 $ 47,754 Capacity revenues 13,624 82 — Total $ 58,619 $ 155,454 $ 47,754 |
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 2023, 2022 or 2021: 2023 2022 2021 Jackson EMC 15.1 % 16.0 % 15.2 % GreyStone Power Corporation, an EMC 11.4 % 9.5 % 12.3 % Cobb EMC 8.5 % 10.0 % 8.7 % |
Schedule of sales to non-members | Sales to members were as follows: (dollars in thousands) 2023 2022 2021 Capacity revenues $ 1,082,368 $ 984,036 $ 946,662 Energy revenues 599,198 990,647 610,447 Total $ 1,681,566 $ 1,974,683 $ 1,557,109 Sales to non-members were as follows: (dollars in thousands) 2023 2022 2021 Energy revenues $ 44,995 $ 155,372 $ 47,754 Capacity revenues 13,624 82 — Total $ 58,619 $ 155,454 $ 47,754 |
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 2023 and 2022. (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2022 $ 820,106 $ 461,528 $ 62,109 $ 1,343,743 Liabilities incurred 62,841 — — 62,841 Liabilities settled — (14,445) (76) (14,521) Accretion 46,857 16,558 2,492 65,907 Deferred accretion — 5 — 5 Change in cash flow estimates — 321 641 962 Balance at December 31, 2023 $ 929,804 $ 463,967 $ 65,166 $ 1,458,937 (dollars in thousands) Nuclear Coal Ash Pond Other Total Balance at December 31, 2021 $ 778,214 $ 442,686 $ 66,243 $ 1,287,143 Liabilities incurred — — — — 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 |
Schedule of estimated costs of decommissioning of co-owned nuclear facilities | Our portion of the estimated costs of decommissioning co-owned nuclear facilities for which we have recorded asset retirement obligations as of December 31, 2023 are as follows: (dollars in thousands) 2021 site study Hatch Hatch Vogtle Vogtle Expected start date of decommissioning 2034 2038 2047 2049 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 (dollars in thousands) 2020 site study Vogtle Expected start date of decommissioning 2061 Estimated costs based on site study in 2020 dollars: Radiated structures $ 187,000 Spent fuel management 19,000 Non-radiated structures 22,000 Total estimated site study costs $ 228,000 |
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, 2023 and December 31, 2022. The funds were invested in a diversified mix of approximately 71% equity and 29% fixed income securities in 2023 and 69% equity and 31% fixed income securities in 2022. 2023 External Trust Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Gain(Loss) Fair Value 12/31/2023 Equity $ 228,936 $ 29,307 $ (9,180) $ 201,900 $ 450,963 Debt 192,986 485,705 (482,935) (4,751) 191,005 Other 91 20,015 (20,835) — (729) $ 422,013 $ 535,027 $ (512,950) $ 197,149 $ 641,239 __________________ (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $22,078,000. 2023 Internal Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value Equity $ 79,122 $ — $ 7,256 $ 39,134 $ 125,512 Debt 43,032 59,630 (53,342) (942) 48,378 $ 122,154 $ 59,630 $ (46,086) $ 38,192 $ 173,890 __________________ (1) Also included in net proceeds are net realized gains or losses, interest income, dividends, contributions and fees of $13,542,000. 2022 External Trust Funds: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value 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: (dollars in thousands) Cost Purchases Net Proceeds (1) Unrealized Fair Value 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. |
Schedule of annual depreciation rates | Annual weighted average depreciation rates in effect in 2023, 2022, and 2021 were as follows: Remaining Useful Life Range in years * 2023 2022 2021 Steam production 19-21 3.05 % 13.77 % 14.47 % Nuclear production 11-59 1.87 % 2.17 % 2.18 % Hydro production 43 2.00 % 2.00 % 2.00 % Other production 16-30 2.73 % 2.68 % 2.60 % Transmission 11-59 2.75 % 2.75 % 2.75 % General 1-42 2.00-33.33% 2.00-33.33% 2.00-33.33% __________________ * |
Reconciliation of cash, cash equivalents and restricted cash | 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, 2023 December 31, 2022 (dollars in thousands) Cash and cash equivalents $ 490,592 $ 595,381 Restricted cash included in restricted cash and short-term investments — 30,400 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 490,592 $ 625,781 |
Schedule of regulatory assets and liabilities | (dollars in thousands) 2023 2022 Regulatory Assets: Premium and loss on reacquired debt (a) $ 25,476 $ 29,494 Amortization on financing leases (b) 28,780 31,908 Outage costs (c) 30,040 29,317 Asset retirement obligations – Ashpond and other (l) 343,523 353,212 Asset retirement obligations – Nuclear (l) — 32,192 Depreciation expense - Plant Vogtle (d) 34,125 35,549 Depreciation expense - Plant Wansley (e) 335,884 361,784 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (f) 55,159 54,701 Interest rate options cost (g) 137,463 136,827 Deferral of effects on net margin – TA Smith Energy Facility (h) 130,786 136,730 Other regulatory assets (o) 10,253 10,591 Total Regulatory Assets $ 1,131,489 $ 1,212,305 Regulatory Liabilities: Accumulated retirement costs for other obligations (i) $ 25,992 $ 35,580 Deferral of effects on net margin – Hawk Road Energy Facility (h) 16,020 16,636 Deferral of effects on net margin – BC Smith Energy Facility (p) 546 14,825 Major maintenance reserve (j) 120,547 74,584 Amortization on financing leases (b) 2,658 5,557 Deferred debt service adder (k) 170,466 154,514 Asset retirement obligations – Nuclear (l) 47,217 — Revenue deferral plan (m) 308,507 357,460 Natural gas hedges (n) 13,445 131,804 Other regulatory liabilities (o) 922 1,230 Total Regulatory Liabilities $ 706,320 $ 792,190 Net regulatory assets $ 425,169 $ 420,115 __________________ (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 20 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 commenced in August 2023 after Vogtle Unit No. 3 was placed in service on July 31, 2023. (h) Effects on net margin for TA Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (m) Deferred revenues under a rate management program that allowed for additional collections over a five-year period beginning in 2018. These amounts are being 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 30 years and the amortization periods of other regulatory liabilities range up to 3 years. (p) Effects on net margin for the BC Smith 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, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of assets and liabilities measured at fair value on a recurring basis | Fair Value Measurements at Reporting Date Using December 31, 2023 Quoted Prices in Significant Other Significant (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 234,979 $ 234,979 $ — $ — International equity trust $ 134,911 — 134,911 — Corporate bonds and debt $ 67,986 — 67,900 86 US Treasury securities $ 43,917 43,917 — — Mortgage backed securities $ 58,763 — 58,763 — Domestic mutual funds $ 85,481 85,481 — — Municipal bonds $ 303 — 303 — Federal agency securities $ 7,256 — 7,256 — Non-US Gov't bonds & private placements $ 2,717 — 2,717 — International mutual funds $ 2,012 — 2,012 — Other $ 2,914 2,914 — — Long-term investments: International equity trust $ 43,202 — 43,202 — Corporate bonds and debt $ 14,151 — 14,151 — US Treasury securities $ 17,243 17,243 — — Mortgage backed securities $ 15,024 — 15,024 — Domestic mutual funds $ 378,387 378,387 — — Treasury STRIPS $ 220,765 — 220,765 — Non-US Gov't bonds & private placements $ 1,568 — 1,568 — Other $ 392 392 — — Short-term investments: Treasury STRIPS $ 143,931 — 143,931 — Natural gas swaps $ 13,445 — 13,445 — Fair Value Measurements at Reporting Date Using December 31, 2022 Quoted Prices in Significant Other Significant (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 204,129 $ 204,129 $ — $ — International equity trust $ 111,266 — 111,266 — Corporate bonds and debt $ 60,806 — 60,788 18 US Treasury securities $ 49,775 49,775 — — Mortgage backed securities $ 41,210 — 41,210 — Domestic mutual funds $ 57,348 57,348 — — Federal agency securities $ 2,037 — 2,037 — Non-US Gov't bonds & private placements $ 2,890 — 2,890 — International mutual funds $ 653 653 Other $ 10,602 10,602 — — Long-term investments: International equity trust $ 33,606 — 33,606 — Corporate bonds and debt $ 10,473 — 10,473 — US Treasury securities $ 15,488 15,488 — — Mortgage backed securities $ 12,113 — 12,113 — Domestic mutual funds $ 302,302 302,302 — — Treasury STRIPS $ 293,281 — 293,281 — Non-US Gov't bonds & private placements $ 1,976 — 1,976 — Other $ 240 240 — — Short-term investments: Treasury STRIPS $ 61,702 61,702 Natural gas swaps $ 131,804 — 131,804 — |
Schedule of estimated fair values of long-term debt, including current maturities | The estimated fair values of our long-term debt, including current maturities at December 31, 2023 and 2022 were as follows: 2023 2022 (in thousands) Carrying Fair Carrying Fair Long-term debt $ 12,096,552 $ 10,638,749 $ 11,940,359 $ 10,194,954 |
Derivative instruments (Tables)
Derivative instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year | The following table reflects the volume activity of our natural gas derivatives as of December 31, 2023 that is expected to settle or mature each year: Year Natural Gas (in millions) 2024 32.4 2025 25.1 2026 20.9 2027 10.3 2028 — Total 88.7 |
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, 2023 and 2022. Consolidated Balance Sheet Location Fair Value 2023 2022 (dollars in thousands) Assets Natural gas swaps Other current assets $ — $ 35,285 Natural gas swaps Other deferred charges $ 25,459 $ 99,725 Liabilities Natural gas swaps Other current liabilities $ 10,370 $ 3,206 Natural gas swaps Other deferred credits $ 1,644 $ — |
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, 2023, 2022 and 2021. Consolidated 2023 2022 2021 (dollars in thousands) Natural gas swaps gains Fuel $ 2,001 $ 121,626 $ 31,440 Natural gas swaps losses Fuel (22,924) (6,587) (1,431) Total $ (20,923) $ 115,039 $ 30,009 |
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, 2023 and 2022. Consolidated Balance 2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 13,445 $ 131,804 Total $ 13,445 $ 131,804 |
Investments (Tables)
Investments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Schedule of Investments [Abstract] | |
Summary of debt and equity securities | The following tables summarize debt and equity securities at December 31, 2023 and 2022. (dollars in thousands) Gross Unrealized 2023 Cost Gains Losses Fair Value Equity $ 344,669 $ 246,795 $ (5,549) $ 585,915 Debt 908,316 3,938 (25,181) 887,073 Other 2,889 61 (36) 2,914 Total $ 1,255,874 $ 250,794 $ (30,766) $ 1,475,902 (dollars in thousands) Gross Unrealized 2022 Cost Gains Losses Fair Value 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 |
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, 2023 and 2022 are as follows: (dollars in thousands) 2023 2022 Cost Fair Value Cost Fair Value Due within one year $ 486,602 $ 477,726 $ 367,199 $ 353,180 Due after one year through five years 267,690 260,193 293,523 275,073 Due after five years through ten years 47,804 47,416 66,255 62,576 Due after ten years 106,220 101,738 106,058 96,209 Total $ 908,316 $ 887,073 $ 833,035 $ 787,038 |
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, 2023, 2022 and 2021: (dollars in thousands) 2023 2022 2021 Gross realized gains $ 15,518 $ 10,029 $ 33,501 Gross realized losses (8,564) (31,979) (19,985) Proceeds from sales 720,186 301,128 913,600 |
Schedule of investments in associated companies | Investments in associated companies were as follows at December 31, 2023 and 2022: (dollars in thousands) 2023 2022 National Rural Utilities Cooperative Finance Corporation (CFC) $ 24,068 $ 24,081 CT Parts, LLC 6,568 6,574 Georgia Transmission Corporation 40,806 38,287 Georgia System Operations Corporation 6,500 7,750 Other 4,191 2,245 Total $ 82,133 $ 78,937 |
Income taxes (Tables)
Income taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
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: 2023 2022 2021 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, 2023 and 2022 were as follows: (dollars in thousands) 2023 2022 Deferred tax assets Net operating losses $ 109,447 $ 115,080 Obligation related to asset retirements 375,530 345,879 Advance payments 176,956 183,833 Other regulatory liabilities 23,652 18,687 Other assets 30,085 30,373 Deferred tax assets 715,670 693,852 Less: Valuation allowance — — Net deferred tax assets $ 715,670 $ 693,852 Deferred tax liabilities Fixed assets and intangibles $ (154,219) $ (140,095) Right-of-use assets-finance leases (77,923) (77,923) Other regulatory asset (373,802) (343,230) Other liabilities (15,679) (15,352) Deferred tax liabilities (621,623) (576,600) Net deferred tax assets (liabilities) $ 94,047 $ 117,252 Less: Patronage exclusion (94,047) (117,252) Net deferred taxes $ — $ — |
Leases (Tables)
Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Schedule of balance sheet impact of leases | We combine lease and nonlease components for all lease agreements. Classification 2023 2022 (dollars in thousands) Right-of-use assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (278,586) (272,876) Total finance lease assets $ 24,146 $ 29,856 Lease liabilities - Finance leases Obligations under finance leases $ 43,586 $ 52,937 Long-term debt and finance leases due within one year 9,351 8,398 Total finance lease liabilities $ 52,937 $ 61,335 Classification 2023 2022 (dollars in thousands) Right-of-use assets - Operating leases Electric plant in service, net $ 6,587 $ 3,326 Total operating lease assets $ 6,587 $ 3,326 Lease liabilities - Operating leases Capitalization - Other $ 5,152 $ 2,256 Other current liabilities 1,529 1,164 Total operating lease liabilities $ 6,681 $ 3,420 |
Schedule of lease cost | 2023 2022 (dollars in thousands) Lease Cost Classification Finance lease cost: Amortization of leased assets Depreciation and amortization $ 8,398 $ 7,542 Interest on lease liabilities Interest expense $ 6,551 $ 7,408 Operating lease cost Inventory (1) & production expense $ 1,441 $ 995 Total lease cost $ 16,390 $ 15,945 __________________ (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. |
Summary of lease terms and discount rates | December 31, 2023 December 31, 2022 Lease Term and Discount Rate Weighted-average remaining lease term (in years): Finance leases 5.26 5.94 Operating leases 5.77 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 6.37 % 5.52 % |
Schedule of cash paid for amounts included in the measurement of lease liabilities | 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 6,551 $ 7,408 Operating cash flows from operating leases $ 1,410 $ 1,009 Financing cash flows from finance leases $ 8,398 $ 7,541 Right-of-use assets obtained in exchange for new operating lease liabilities $ 4,503 $ 1,954 |
Schedule of maturities of finance operating lease liabilities | Maturity analysis of our finance and operating lease liabilities as of December 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2024 $ 14,949 $ 1,913 $ 16,862 2025 14,949 1,703 16,652 2026 14,949 1,412 16,361 2027 14,949 1,134 16,083 2028 3,052 1,026 4,078 Thereafter 7,633 795 8,428 Total lease payments $ 70,481 $ 7,983 $ 78,464 Less: imputed interest (17,544) (1,302) (18,846) Present value of lease liabilities $ 52,937 $ 6,681 $ 59,618 |
Schedule of maturities of operating lease liabilities | Maturity analysis of our finance and operating lease liabilities as of December 31, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2024 $ 14,949 $ 1,913 $ 16,862 2025 14,949 1,703 16,652 2026 14,949 1,412 16,361 2027 14,949 1,134 16,083 2028 3,052 1,026 4,078 Thereafter 7,633 795 8,428 Total lease payments $ 70,481 $ 7,983 $ 78,464 Less: imputed interest (17,544) (1,302) (18,846) Present value of lease liabilities $ 52,937 $ 6,681 $ 59,618 |
Schedule of lessor's income from leases | Lease income recognized during 2023 and 2022 was as follows: 2023 2022 (dollars in thousands) Lease income $ 6,776 $ 6,539 |
Debt (Tables)
Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Debt Disclosure [Abstract] | |
Schedule of maturities for long-term debt and finance lease obligations | Maturities for long-term debt and finance lease obligations through 2028 are as follows: (dollars in thousands) 2024 2025 2026 2027 2028 FFB $ 311,565 $ 284,714 $ 265,177 $ 242,177 $ 283,089 FMBs 63,510 62,500 62,500 62,500 62,500 PCRBs — — — — — $ 375,075 $ 347,214 $ 327,677 $ 304,677 $ 345,589 Finance Leases 9,351 10,413 11,595 12,912 2,153 Total $ 384,426 $ 357,627 $ 339,272 $ 317,589 $ 347,742 |
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, 2023 and December 31, 2022 are as follows: 2023 2022 Principal Unamortized Debt Principal Unamortized Debt (dollars in thousands) FFB $ 6,841,352 $ 51,083 $ 7,084,148 $ 52,690 FMBs 4,551,010 60,987 4,152,021 52,480 PCRBs 704,190 8,490 704,190 8,972 $ 12,096,552 $ 120,560 $ 11,940,359 $ 114,142 |
Electric plant, construction _2
Electric plant, construction and related agreements (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Property, Plant and Equipment [Abstract] | |
Summary of plant investments and related accumulated depreciation | A summary of our plant investments and related accumulated depreciation as of December 31, 2023 and 2022 is as follows: 2023 2022 (dollars in thousands) Plant Investment Accumulated Investment Accumulated In-service (1) Owned property Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership) $ 3,035,806 $ (1,948,158) $ 3,024,112 $ (1,916,942) Vogtle Unit No. 3 (Nuclear – 30% ownership) 4,771,526 (43,418) 58,189 (8,627) Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership) 1,019,809 (559,001) 991,852 (533,771) Wansley Units No. 1 & No. 2 (Fossil – 30% ownership) 24,710 (27,152) 20,312 (15,337) Scherer Unit No. 1 (Fossil – 60% ownership) 1,372,241 (660,580) 1,378,904 (636,799) Doyle (Combustion Turbine - 100% ownership) 148,902 (127,378) 145,780 (124,306) Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership) 618,955 (308,827) 616,278 (296,624) Hartwell (Combustion Turbine - 100% ownership) 233,662 (131,434) 232,532 (125,092) Hawk Road (Combustion Turbine - 100% ownership) 272,416 (79,985) 269,837 (74,685) Talbot (Combustion Turbine - 100% ownership) 308,837 (167,033) 301,869 (162,137) Chattahoochee (Combined cycle - 100% ownership) 343,531 (168,292) 324,310 (171,272) BC Smith (Combined cycle - 100% ownership) 352,005 (126,886) 339,189 (121,318) TA Smith (Combined cycle - 100% ownership) 689,198 (228,997) 686,517 (208,142) Washington County (Combustion Turbine – 100% ownership) 171,034 (92,498) 170,432 (88,585) Baconton (Combustion Turbine – 100% ownership) 32,987 (16,379) — — Transmission plant 122,452 (65,784) 107,992 (64,785) Other 101,061 (60,710) 106,424 (65,922) Property under finance lease: Scherer Unit No. 2 (Fossil – 60% leasehold) 795,698 (606,226) 794,830 (569,245) Total in-service $ 14,414,830 $ (5,418,738) $ 9,569,359 $ (5,183,589) Construction work in progress Vogtle Unit No. 4 $ 3,128,720 $ 7,583,291 Environmental and other generation improvements 165,921 132,744 Total construction work in progress $ 3,294,641 $ 7,716,035 _______________ (1) Amounts include plant acquisition adjustments at December 31, 2023 of $290,725,000 and December 31, 2022 of $280,396,000. (2) Plant Vogtle Unit No. 3 was placed in service on July 31, 2023. |
Commitments (Tables)
Commitments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Commitments and Contingencies Disclosure [Abstract] | |
Schedule of estimated commitments | As of December 31, 2023, our estimated commitments are as follows: (dollars in thousands) Coal Nuclear Fuel Gas Maintenance Asset Finance and Operating Leases 2024 $ 33,810 $ 95,520 $ 66,186 $ 57,749 $ 51,378 $ 16,862 2025 15,938 36,000 67,368 43,025 39,673 16,652 2026 9,362 32,250 69,578 15,736 45,923 16,361 2027 — 28,800 73,075 3,237 59,885 16,083 2028 — 28,500 68,971 46,964 71,267 4,078 Thereafter — 45,660 835,212 269,196 5,065,526 8,428 |
Plant Acquisitions (Tables)
Plant Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Schedule of identifiable assets acquired and liabilities assumed | The following amounts represent the identifiable assets acquired and liabilities assumed in the Baconton acquisition: Classification (dollars in thousands) Recognized identifiable assets acquired and liabilities assumed: Electric plant in service, net $ 16,450 Other current assets 323 Other current liabilities (30) Total identifiable net assets $ 16,743 |
Quarterly financial data (una_2
Quarterly financial data (unaudited) (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Quarterly Financial Data [Abstract] | |
Summary of quarterly financial information | Summarized quarterly financial information for 2023 and 2022 is as follows: First Second Third Fourth (dollars in thousands) 2023 Operating revenues $ 389,453 $ 389,389 $ 500,776 $ 460,567 Operating margin 57,006 49,987 92,317 77,756 Net margin 24,410 18,414 27,127 (4,161) 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) |
Summary of significant accoun_4
Summary of significant accounting policies - Business description (Details) | 12 Months Ended |
Dec. 31, 2023 member MW | |
Business description | |
Number of electric distribution cooperative members | member | 38 |
Summer planning reserve capacity of generating units (in megawatts) | 7,792 |
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) | 756 |
Green Power EMC | Solar energy | |
Business description | |
Summer planning reserve capacity of generating units (in megawatts) | 724 |
Summary of significant accoun_5
Summary of significant accounting policies - Patronage capital and membership fees and Margin policy (Details) | 12 Months Ended | ||
Dec. 31, 2023 USD ($) | Dec. 31, 2022 | Dec. 31, 2021 | |
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) $ in Thousands | 12 Months Ended | 72 Months Ended | ||
Dec. 31, 2023 USD ($) member service | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2023 USD ($) | |
Revenue Recognition | ||||
Number of electric distribution cooperative members | member | 38 | |||
Number of services provided | service | 2 | |||
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 | $ 34,266 | $ 28,471 | $ 34,266 | |
Total revenues | 1,740,185 | 2,130,137 | $ 1,604,863 | |
Operating revenues | ||||
Amount remaining to be credited | 308,507 | 308,507 | ||
Vogtle Units No. 3 & No. 4 | ||||
Operating revenues | ||||
Recovery of financing costs | 9,261 | 14,796 | 15,693 | |
Cumulative recovery of financing costs | $ 135,693 | |||
Additional collection period (in years) | 5 years | |||
Billed amount | $ 52,378 | 11,774 | 143,000 | 369,102 |
Sales to members | ||||
Revenue Recognition | ||||
Total revenues | 1,681,566 | 1,974,683 | 1,557,109 | |
Operating revenues | ||||
Receivables | $ 170,901 | $ 187,401 | $ 143,715 | 170,901 |
Jackson EMC | Total operating revenues | Revenues of members | ||||
Operating revenues | ||||
Concentration risk (as a percent) | 15.10% | 16% | 15.20% | |
Cobb EMC | Total operating revenues | Revenues of members | ||||
Operating revenues | ||||
Concentration risk (as a percent) | 11.40% | 9.50% | 12.30% | |
GreyStone Power Corporation, an EMC | Total operating revenues | Revenues of members | ||||
Operating revenues | ||||
Concentration risk (as a percent) | 8.50% | 10% | 8.70% | |
Sales to non-members | ||||
Revenue Recognition | ||||
Total revenues | $ 58,619 | $ 155,454 | $ 47,754 | |
Operating revenues | ||||
Receivables | 30,883 | 32,614 | $ 30,883 | |
Capacity revenues | Sales to members | ||||
Revenue Recognition | ||||
Total revenues | 1,082,368 | 984,036 | 946,662 | |
Capacity revenues | Sales to non-members | ||||
Revenue Recognition | ||||
Total revenues | 13,624 | 82 | 0 | |
Energy revenues | Sales to members | ||||
Revenue Recognition | ||||
Total revenues | 599,198 | 990,647 | 610,447 | |
Energy revenues | Sales to non-members | ||||
Revenue Recognition | ||||
Total revenues | $ 44,995 | $ 155,372 | $ 47,754 |
Summary of significant accoun_7
Summary of significant accounting policies - Receivables (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Receivables | |||
Impairment losses | $ 0 | $ 0 | $ 0 |
Sales to members | |||
Receivables | |||
Receivables | 170,901,000 | 187,401,000 | $ 143,715,000 |
Sales to non-members | |||
Receivables | |||
Receivables | $ 30,883,000 | $ 32,614,000 |
Summary of significant accoun_8
Summary of significant accounting policies - Nuclear fuel cost (Details) - USD ($) | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2019 | |
Nuclear fuel cost | ||||
Nuclear fuel expense | $ 84,192,000 | $ 73,871,000 | $ 77,366,000 | |
Litigation Nuclear Fuel Disposal Cost 1/1/2011-12/31/2019 | Pending litigation | Plant Hatch and Plant Vogtle | ||||
Nuclear fuel cost | ||||
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 ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Feb. 14, 2024 | Mar. 06, 2023 | |
Asset retirement obligations | |||||
Balance at the beginning of the period | $ 1,343,743 | $ 1,287,143 | |||
Liabilities incurred | 62,841 | 0 | |||
Liabilities settled | (14,521) | (10,318) | |||
Accretion | 65,907 | 55,953 | $ 56,086 | ||
Deferred accretion | 5 | 479 | |||
Change in cash flow estimates | 962 | 10,486 | |||
Balance at the end of the period | 1,458,937 | 1,343,743 | 1,287,143 | ||
Coal Combustion Residuals | |||||
Cost to close plant | 1,458,937 | 1,343,743 | 1,287,143 | ||
Increase in the obligation for coal ash decommissioning | 321 | 16,301 | |||
Fund balances for coal ash pond and landfill decommissioning | 176,630 | 153,208 | |||
Hatch Unit No. 1 | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 302,000 | ||||
Hatch Unit No. 1 | Radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 227,000 | ||||
Hatch Unit No. 1 | Spent fuel management | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 60,000 | ||||
Hatch Unit No. 1 | Non-radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 15,000 | ||||
Hatch Unit No. 2 | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 308,000 | ||||
Hatch Unit No. 2 | Radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 236,000 | ||||
Hatch Unit No. 2 | Spent fuel management | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 51,000 | ||||
Hatch Unit No. 2 | Non-radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 21,000 | ||||
Vogtle Unit No. 1 | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 282,000 | ||||
Vogtle Unit No. 1 | Radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 200,000 | ||||
Vogtle Unit No. 1 | Spent fuel management | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 58,000 | ||||
Vogtle Unit No. 1 | Non-radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 24,000 | ||||
Vogtle Unit No. 2 | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 297,000 | ||||
Vogtle Unit No. 2 | Radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 213,000 | ||||
Vogtle Unit No. 2 | Spent fuel management | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 53,000 | ||||
Vogtle Unit No. 2 | Non-radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 31,000 | ||||
Vogtle Unit No. 3 | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 228,000 | ||||
Coal Combustion Residuals | |||||
Cost to close plant | $ 62,841 | ||||
Vogtle Unit No. 3 | Radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 187,000 | ||||
Vogtle Unit No. 3 | Spent fuel management | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 19,000 | ||||
Vogtle Unit No. 3 | Non-radiated structures | |||||
Nuclear Decommissioning | |||||
Estimated costs based on site study | 22,000 | ||||
Vogtle Unit Number 4 | Subsequent Event | |||||
Coal Combustion Residuals | |||||
Cost to close plant | $ 65,000 | ||||
Nuclear | |||||
Asset retirement obligations | |||||
Balance at the beginning of the period | 820,106 | 778,214 | |||
Liabilities incurred | 62,841 | 0 | |||
Liabilities settled | 0 | 0 | |||
Accretion | 46,857 | 41,892 | |||
Deferred accretion | 0 | 0 | |||
Change in cash flow estimates | 0 | 0 | |||
Balance at the end of the period | 929,804 | 820,106 | 778,214 | ||
Coal Combustion Residuals | |||||
Cost to close plant | 929,804 | 820,106 | 778,214 | ||
Coal Ash Pond | |||||
Asset retirement obligations | |||||
Balance at the beginning of the period | 461,528 | 442,686 | |||
Liabilities incurred | 0 | 0 | |||
Liabilities settled | (14,445) | (10,134) | |||
Accretion | 16,558 | 12,196 | |||
Deferred accretion | 5 | 479 | |||
Change in cash flow estimates | 321 | 16,301 | |||
Balance at the end of the period | 463,967 | 461,528 | 442,686 | ||
Coal Combustion Residuals | |||||
Cost to close plant | 463,967 | 461,528 | 442,686 | ||
Other | |||||
Asset retirement obligations | |||||
Balance at the beginning of the period | 62,109 | 66,243 | |||
Liabilities incurred | 0 | 0 | |||
Liabilities settled | (76) | (184) | |||
Accretion | 2,492 | 1,865 | |||
Deferred accretion | 0 | 0 | |||
Change in cash flow estimates | 641 | (5,815) | |||
Balance at the end of the period | 65,166 | 62,109 | 66,243 | ||
Coal Combustion Residuals | |||||
Cost to close plant | $ 65,166 | $ 62,109 | $ 66,243 |
Summary of significant accou_10
Summary of significant accounting policies - Nuclear decommissioning funds (Details) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Nuclear decommissioning funds | |||
Additional contribution to external trust funds | $ 4,619,000 | $ 2,643,000 | |
Additional amount collected for nuclear decommissioning | $ 10,000,000 | $ 8,350,000 | |
Percentage of decommissioning fund classified as equity | 71% | 69% | |
Percentage of decommissioning funds classified as fixed income securities | 29% | 31% | |
External and Internal Trust Funds: | |||
Purchases | $ 535,027,000 | $ 204,500,000 | $ 675,153,000 |
Fair Value | $ 641,239,000 | 540,716,000 | |
Average annualized rate of return over the past ten years | 6.20% | ||
Average annualized rate of return since inception | 6% | ||
External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 422,013,000 | 427,476,000 | |
Purchases | $ 535,027,000 | 204,500,000 | |
Net Proceeds | (512,950,000) | (209,963,000) | |
Unrealized Gain(Loss) | 197,149,000 | 118,703,000 | |
Fair Value | 641,239,000 | 540,716,000 | |
Net realized gains or losses, interest income and dividends, contributions and fees | 22,078,000 | 5,463,000 | |
Internal Funds | |||
External and Internal Trust Funds: | |||
Cost | 122,154,000 | 115,770,000 | |
Purchases | 59,630,000 | 76,207,000 | |
Net Proceeds | (46,086,000) | (69,823,000) | |
Unrealized Gain(Loss) | 38,192,000 | 16,254,000 | |
Fair Value | 173,890,000 | 138,408,000 | |
Net realized gains or losses, interest income and dividends, contributions and fees | 13,542,000 | 6,384,000 | |
Equity | External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 228,936,000 | 223,336,000 | |
Purchases | 29,307,000 | 9,255,000 | |
Net Proceeds | (9,180,000) | (3,655,000) | |
Unrealized Gain(Loss) | 201,900,000 | 131,572,000 | |
Fair Value | 450,963,000 | 360,508,000 | |
Equity | Internal Funds | |||
External and Internal Trust Funds: | |||
Cost | 79,122,000 | 68,914,000 | |
Purchases | 0 | 0 | |
Net Proceeds | 7,256,000 | 10,005,000 | |
Unrealized Gain(Loss) | 39,134,000 | 18,995,000 | |
Fair Value | 125,512,000 | 97,914,000 | |
Debt | External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 192,986,000 | 204,935,000 | |
Purchases | 485,705,000 | 191,958,000 | |
Net Proceeds | (482,935,000) | (203,907,000) | |
Unrealized Gain(Loss) | (4,751,000) | (12,869,000) | |
Fair Value | 191,005,000 | 180,117,000 | |
Debt | Internal Funds | |||
External and Internal Trust Funds: | |||
Cost | 43,032,000 | 46,856,000 | |
Purchases | 59,630,000 | 76,207,000 | |
Net Proceeds | (53,342,000) | (79,828,000) | |
Unrealized Gain(Loss) | (942,000) | (2,741,000) | |
Fair Value | 48,378,000 | 40,494,000 | |
Other | External Trust Funds | |||
External and Internal Trust Funds: | |||
Cost | 91,000 | $ (795,000) | |
Purchases | 20,015,000 | 3,287,000 | |
Net Proceeds | (20,835,000) | (2,401,000) | |
Unrealized Gain(Loss) | 0 | 0 | |
Fair Value | $ (729,000) | $ 91,000 |
Summary of significant accou_11
Summary of significant accounting policies - Depreciation and Electric plant (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Depreciation | |||
Depreciation expense | $ 321,047 | $ 278,452 | $ 269,280 |
Increase (decrease) in depreication expense | 42,595 | ||
Regulatory assets | $ 1,131,489 | $ 1,212,305 | |
Electric plant | |||
Allowance for funds used during construction (as a percent) | 4.18% | 4.03% | 3.90% |
Steam production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 3.05% | 13.77% | 14.47% |
Steam production | Minimum | |||
Depreciation | |||
Remaining life of the plant | 19 years | ||
Steam production | Maximum | |||
Depreciation | |||
Remaining life of the plant | 21 years | ||
Nuclear production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 1.87% | 2.17% | 2.18% |
Nuclear production | Minimum | |||
Depreciation | |||
Remaining life of the plant | 11 years | ||
Nuclear production | Maximum | |||
Depreciation | |||
Remaining life of the plant | 59 years | ||
Hydro production | |||
Depreciation | |||
Remaining life of the plant | 43 years | ||
Annual depreciation rates (as a percent) | 2% | 2% | 2% |
Other production | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 2.73% | 2.68% | 2.60% |
Other production | Minimum | |||
Depreciation | |||
Remaining life of the plant | 16 years | ||
Other production | Maximum | |||
Depreciation | |||
Remaining life of the plant | 30 years | ||
Transmission | |||
Depreciation | |||
Annual depreciation rates (as a percent) | 2.75% | 2.75% | 2.75% |
Transmission | Minimum | |||
Depreciation | |||
Remaining life of the plant | 11 years | ||
Transmission | Maximum | |||
Depreciation | |||
Remaining life of the plant | 59 years | ||
General | Minimum | |||
Depreciation | |||
Remaining life of the plant | 1 year | ||
Annual depreciation rates (as a percent) | 2% | 2% | 2% |
General | Maximum | |||
Depreciation | |||
Remaining life of the plant | 42 years | ||
Annual depreciation rates (as a percent) | 33.33% | 33.33% | 33.33% |
Wansley | |||
Depreciation | |||
Depreciation expense | $ 25,900 | $ 8,120 | |
Wansley | Depreciation expense | |||
Depreciation | |||
Deferred depreciation expense | 165,013 | 204,891 | |
Regulatory assets | $ 335,884 | $ 361,784 |
Summary of significant accou_12
Summary of significant accounting policies - Restricted investments (Details) - USD ($) | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Restricted investments | $ 0 | $ 74,031,000 |
Summary of significant accou_13
Summary of significant accounting policies - Reconciliation of cash, cash equivalents and restricted cash (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Dec. 31, 2020 |
Accounting Policies [Abstract] | ||||
Cash and cash equivalents | $ 490,592 | $ 595,381 | ||
Restricted cash included in restricted cash and short-term investments | 0 | 30,400 | ||
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows | $ 490,592 | $ 625,781 | $ 581,150 | $ 405,511 |
Restricted Cash, Statement of Financial Position [Extensible Enumeration] | Restricted cash and short-term investments |
Summary of significant accou_14
Summary of significant accounting policies - Inventories (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Accounting Policies [Abstract] | ||
Fossil fuels inventories | $ 74,149 | $ 64,386 |
Spare parts | $ 262,896 | $ 233,565 |
Summary of significant accou_15
Summary of significant accounting policies - Regulatory assets and liabilities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 1,131,489 | $ 1,212,305 |
Total Regulatory Liabilities | 706,320 | 792,190 |
Net Regulatory Assets | 425,169 | 420,115 |
Accumulated retirement costs for other obligations | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 25,992 | 35,580 |
Deferral of effects on net margin | Hawk Road Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 16,020 | 16,636 |
Deferral of effects on net margin | BC Smith Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 546 | 14,825 |
Major maintenance reserve | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 120,547 | 74,584 |
Amortization on capital leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 2,658 | 5,557 |
Deferred debt service adder | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 170,466 | 154,514 |
Nuclear | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 47,217 | 0 |
Revenue deferral plan | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 308,507 | 357,460 |
Amortization period, other regulatory liabilities | 5 years | |
Natural gas hedge | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 13,445 | 131,804 |
Other regulatory liabilities | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 922 | 1,230 |
Other regulatory liabilities | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory liabilities | 3 years | |
Premium and loss on reacquired debt | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 25,476 | 29,494 |
Premium and loss on reacquired debt | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 20 years | |
Amortization on financing leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 28,780 | 31,908 |
Outage costs | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 30,040 | 29,317 |
Coal-fired maintenance outage costs | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 60 months | |
Nuclear refueling outage costs | Minimum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 18 months | |
Nuclear refueling outage costs | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 24 months | |
Asset retirement obligations - Ashpond and other | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 343,523 | 353,212 |
Nuclear | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 0 | 32,192 |
Depreciation expense | Plant Vogtle | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 34,125 | 35,549 |
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 | $ 335,884 | 361,784 |
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units No. 3 & No. 4 | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 55,159 | 54,701 |
Interest rate options cost | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 137,463 | 136,827 |
Deferral of effects on net margin | TA Smith Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 130,786 | 136,730 |
Other regulatory assets | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 10,253 | $ 10,591 |
Other regulatory assets | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 30 years |
Summary of significant accou_16
Summary of significant accounting policies - Related parties (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 USD ($) member | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Related parties | |||
Number of electric distribution cooperative members | 38 | ||
Related Party | Georgia Transmission Corporation | |||
Related parties | |||
Number of electric distribution cooperative members | 38 | ||
General and administrative expense | $ | $ 41,426 | $ 40,774 | $ 39,677 |
Related Party | Georgia System Operations Corporation | |||
Related parties | |||
Number of electric distribution cooperative members | 38 | ||
General and administrative expense | $ | $ 30,109 | $ 27,416 | $ 26,936 |
Fair Value - Asset and liabilit
Fair Value - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Fair value | ||
Nuclear decommissioning trust fund | $ 641,239,000 | $ 540,716,000 |
Long-term investments | 690,732,000 | 669,479,000 |
Short-term investments | 143,931,000 | 61,702,000 |
International equity trust | ||
Fair value | ||
Unfunded commitments | $ 0 | |
Redemption notice period | 3 days | |
Recurring basis | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | $ 13,445,000 | 131,804,000 |
Recurring basis | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 234,979,000 | 204,129,000 |
Recurring basis | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 134,911,000 | 111,266,000 |
Long-term investments | 43,202,000 | 33,606,000 |
Recurring basis | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 67,986,000 | 60,806,000 |
Long-term investments | 14,151,000 | 10,473,000 |
Recurring basis | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 43,917,000 | 49,775,000 |
Long-term investments | 17,243,000 | 15,488,000 |
Recurring basis | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 58,763,000 | 41,210,000 |
Long-term investments | 15,024,000 | 12,113,000 |
Recurring basis | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 85,481,000 | 57,348,000 |
Long-term investments | 378,387,000 | 302,302,000 |
Recurring basis | Municipal bonds | ||
Fair value | ||
Nuclear decommissioning trust fund | 303,000 | 2,037,000 |
Recurring basis | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 7,256,000 | |
Long-term investments | 293,281,000 | |
Recurring basis | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,717,000 | 2,890,000 |
Long-term investments | 1,568,000 | |
Recurring basis | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,012,000 | 653,000 |
Recurring basis | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 220,765,000 | 1,976,000 |
Short-term investments | 143,931,000 | 61,702,000 |
Recurring basis | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,914,000 | 10,602,000 |
Long-term investments | 392,000 | 240,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 234,979,000 | 204,129,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 43,917,000 | 49,775,000 |
Long-term investments | 17,243,000 | 15,488,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 85,481,000 | 57,348,000 |
Long-term investments | 378,387,000 | 302,302,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | |
Long-term investments | 0 | |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 0 | 0 |
Short-term investments | 0 | |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,914,000 | 10,602,000 |
Long-term investments | 392,000 | 240,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 13,445,000 | 131,804,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 134,911,000 | 111,266,000 |
Long-term investments | 43,202,000 | 33,606,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 67,900,000 | 60,788,000 |
Long-term investments | 14,151,000 | 10,473,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 58,763,000 | 41,210,000 |
Long-term investments | 15,024,000 | 12,113,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds | ||
Fair value | ||
Nuclear decommissioning trust fund | 303,000 | 2,037,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 7,256,000 | |
Long-term investments | 293,281,000 | |
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,717,000 | 2,890,000 |
Long-term investments | 1,568,000 | |
Recurring basis | Significant Other Observable Inputs (Level 2) | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,012,000 | 653,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 220,765,000 | 1,976,000 |
Short-term investments | 143,931,000 | 61,702,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 86,000 | 18,000 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Municipal bonds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | Significant Unobservable Inputs (Level 3) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | |
Long-term investments | 0 | |
Recurring basis | Significant Unobservable Inputs (Level 3) | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | |
Recurring basis | Significant Unobservable Inputs (Level 3) | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | |
Recurring basis | Significant Unobservable Inputs (Level 3) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 0 | 0 |
Short-term investments | 0 | |
Recurring basis | Significant Unobservable Inputs (Level 3) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | $ 0 | $ 0 |
Fair Value - Estimated fair val
Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Carrying Value | ||
Fair Value | ||
Long-term debt | $ 12,096,552 | $ 11,940,359 |
Fair Value | Significant Other Observable Inputs (Level 2) | ||
Fair Value | ||
Long-term debt | $ 10,638,749 | $ 10,194,954 |
Derivative instruments - Gas he
Derivative instruments - Gas hedges (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions | 12 Months Ended | |
Dec. 31, 2023 USD ($) MMBTU | Dec. 31, 2022 USD ($) | |
Derivative Instruments | ||
Derivative asset | $ | $ 13,445 | $ 131,804 |
Credit collateral posted | $ | $ 30,400 | |
Notional volume of natural gas derivatives (in MMBTUs) | 88.7 | |
2024 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 32.4 | |
2025 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 25.1 | |
2026 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 20.9 | |
2027 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 10.3 | |
2028 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 0 |
Derivative instruments - Fair v
Derivative instruments - Fair value of derivative instruments not designated as hedging (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Liabilities: | ||
Derivative Liability, Statement of Financial Position [Extensible Enumeration] | Other current liabilities | |
Natural gas swaps | ||
Assets: | ||
Assets | $ 13,445 | $ 131,804 |
Not designated as hedges | Natural gas swaps | Other current assets | ||
Assets: | ||
Assets | 0 | 35,285 |
Not designated as hedges | Natural gas swaps | Other deferred charges | ||
Assets: | ||
Assets | 25,459 | 99,725 |
Not designated as hedges | Natural gas swaps | Other current liabilities | ||
Liabilities: | ||
Liabilities | 10,370 | 3,206 |
Not designated as hedges | Natural gas swaps | Other deferred credits | ||
Liabilities: | ||
Liabilities | $ 1,644 | $ 0 |
Derivative instruments - Realiz
Derivative instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Gains and (losses) on derivative instruments | |||
Net unrealized losses on derivative instruments | $ 13,445 | $ 131,804 | |
Natural gas swaps | |||
Gains and (losses) on derivative instruments | |||
Gains | 2,001 | 121,626 | $ 31,440 |
Losses | (22,924) | (6,587) | (1,431) |
Total | (20,923) | 115,039 | $ 30,009 |
Natural gas swaps | Regulatory liability | |||
Gains and (losses) on derivative instruments | |||
Net unrealized losses on derivative instruments | $ 13,445 | $ 131,804 |
Investments - Investments in De
Investments - Investments in Debt and Equity Securities (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Cost | ||
Equity | $ 344,669 | $ 323,907 |
Debt | 908,316 | 833,035 |
Other | 2,889 | 10,445 |
Total | 1,255,874 | 1,167,387 |
Gross Unrealized Gains | ||
Equity | 246,795 | 159,445 |
Debt | 3,938 | 372 |
Other | 61 | 20 |
Total | 250,794 | 159,837 |
Gross Unrealized Losses | ||
Equity | (5,549) | (8,949) |
Debt | (25,181) | (46,369) |
Other | (36) | (9) |
Total | (30,766) | (55,327) |
Fair Value | ||
Equity | 585,915 | 474,403 |
Debt | 887,073 | 787,038 |
Other | 2,914 | 10,456 |
Total | $ 1,475,902 | $ 1,271,897 |
Investments - Narrative (Detail
Investments - Narrative (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Investment Company [Abstract] | |
Amortized cost basis, unrealized loss positions | $ 788,798 |
Unrealized loss position | 25,181 |
Unrealized loss position, less than 12 months | 3,362 |
Unrealized loss position, 12 months or longer | $ 21,819 |
Investments - Contractual Matur
Investments - Contractual Maturities of Debt Securities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Cost | ||
Due within one year | $ 486,602 | $ 367,199 |
Due after one year through five years | 267,690 | 293,523 |
Due after five years through ten years | 47,804 | 66,255 |
Due after ten years | 106,220 | 106,058 |
Total | 908,316 | 833,035 |
Fair Value | ||
Due within one year | 477,726 | 353,180 |
Due after one year through five years | 260,193 | 275,073 |
Due after five years through ten years | 47,416 | 62,576 |
Due after ten years | 101,738 | 96,209 |
Total | $ 887,073 | $ 787,038 |
Investments - Gross realized ga
Investments - Gross realized gains, losses and proceeds from sales of securities (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Schedule of Investments [Abstract] | |||
Gross realized gains | $ 15,518 | $ 10,029 | $ 33,501 |
Gross realized losses | (8,564) | (31,979) | (19,985) |
Proceeds from sales | $ 720,186 | $ 301,128 | $ 913,600 |
Investments - Investment in ass
Investments - Investment in associated companies (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Investment in associated companies | ||
Investment in associated companies | $ 82,133 | $ 78,937 |
National Rural Utilities Cooperative Finance Corporation (CFC) | ||
Investment in associated companies | ||
Investment in associated companies | 24,068 | 24,081 |
CT Parts, LLC | ||
Investment in associated companies | ||
Investment in associated companies | 6,568 | 6,574 |
Georgia Transmission Corporation | ||
Investment in associated companies | ||
Investment in associated companies | 40,806 | 38,287 |
Georgia System Operations Corporation | ||
Investment in associated companies | ||
Investment in associated companies | 6,500 | 7,750 |
Other | ||
Investment in associated companies | ||
Investment in associated companies | $ 4,191 | $ 2,245 |
Investments - Rocky Mountain tr
Investments - Rocky Mountain transactions (Details) - Rocky Mountain $ in Thousands | 2 Months Ended | 12 Months Ended |
Jan. 31, 1997 lease trust investor | 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 | investor | 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 | $ 13,901 | |
Purchase option price | 112,000 | |
Outstanding loan amount | $ 74,000 | |
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 | |
Fund amount under equity funding agreement | $ 37,928 | |
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, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
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 | $ 109,447,000 | $ 115,080,000 | |
Obligation related to asset retirements | 375,530,000 | 345,879,000 | |
Advance payments | 176,956,000 | 183,833,000 | |
Other regulatory liabilities | 23,652,000 | 18,687,000 | |
Other assets | 30,085,000 | 30,373,000 | |
Deferred tax assets | 715,670,000 | 693,852,000 | |
Less: Valuation allowance | 0 | 0 | |
Net deferred tax assets | 715,670,000 | 693,852,000 | |
Deferred tax liabilities | |||
Fixed assets and intangibles | (154,219,000) | (140,095,000) | |
Right-of-use assets-finance leases | (77,923,000) | (77,923,000) | |
Other regulatory asset | (373,802,000) | (343,230,000) | |
Other liabilities | (15,679,000) | (15,352,000) | |
Deferred tax liabilities | (621,623,000) | (576,600,000) | |
Net deferred tax assets (liabilities) | 94,047,000 | 117,252,000 | |
Less: Patronage exclusion | (94,047,000) | (117,252,000) | |
Net deferred taxes | 0 | $ 0 | |
Net operating loss carryforwards | $ 425,203,000 |
Leases - Summary (Details)
Leases - Summary (Details) | 12 Months Ended |
Dec. 31, 2023 lease | |
Lease Disclosure [Line Items] | |
Number of finance leases | 4 |
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, 2023 | Dec. 31, 2022 |
Right-of-use assets - Finance leases | ||
Right-of-use assets | $ 302,732 | $ 302,732 |
Less: Accumulated provision for depreciation | (278,586) | (272,876) |
Total finance lease assets | 24,146 | 29,856 |
Lease liabilities - Finance leases | ||
Obligations under finance leases | 43,586 | 52,937 |
Long-term debt and finance leases due within one year | 9,351 | 8,398 |
Total finance lease liabilities | 52,937 | 61,335 |
Right-of-use assets - Operating leases | ||
Electric plant in service, net | 6,587 | 3,326 |
Total operating lease assets | 6,587 | 3,326 |
Lease liabilities - Operating leases | ||
Capitalization - Other | 5,152 | 2,256 |
Other current liabilities | 1,529 | 1,164 |
Total operating lease liabilities | $ 6,681 | $ 3,420 |
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 Rocky Mountain transactions | Obligation under Rocky Mountain 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, 2023 | Dec. 31, 2022 | |
Lease Cost | ||
Amortization of leased assets | $ 8,398 | $ 7,542 |
Interest on lease liabilities | 6,551 | 7,408 |
Operating lease cost | 1,441 | 995 |
Total lease cost | $ 16,390 | $ 15,945 |
Weighted-average remaining lease term (in years): | ||
Finance leases | 5 years 3 months 3 days | 5 years 11 months 8 days |
Operating leases | 5 years 9 months 7 days | 6 years 5 months 8 days |
Weighted-average discount rate: | ||
Finance leases | 11.05% | 11.05% |
Operating leases | 6.37% | 5.52% |
Leases - Other lease disclosure
Leases - Other lease disclosures (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Lessee Disclosure [Abstract] | ||
Operating cash flows from finance leases | $ 6,551 | $ 7,408 |
Operating cash flows from operating leases | 1,410 | 1,009 |
Financing cash flows from finance leases | 8,398 | 7,541 |
Right-of-use assets obtained in exchange for new operating lease liabilities | 4,503 | 1,954 |
Finance Leases | ||
2024 | 14,949 | |
2025 | 14,949 | |
2026 | 14,949 | |
2027 | 14,949 | |
2028 | 3,052 | |
Thereafter | 7,633 | |
Total lease payments | 70,481 | |
Less: imputed interest | (17,544) | |
Total finance lease liabilities | 52,937 | 61,335 |
Operating Leases | ||
2024 | 1,913 | |
2025 | 1,703 | |
2026 | 1,412 | |
2027 | 1,134 | |
2028 | 1,026 | |
Thereafter | 795 | |
Total lease payments | 7,983 | |
Less: imputed interest | (1,302) | |
Total operating lease liabilities | 6,681 | 3,420 |
Total | ||
2024 | 16,862 | |
2025 | 16,652 | |
2026 | 16,361 | |
2027 | 16,083 | |
2028 | 4,078 | |
Thereafter | 8,428 | |
Total lease payments | 78,464 | |
Less: imputed interest | (18,846) | |
Present value of lease liabilities | 59,618 | |
Lessor Disclosure [Abstract] | ||
Lease income | $ 6,776 | $ 6,539 |
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, 2023 | Dec. 31, 2022 |
Maturities for finance leases | ||
2024 | $ 14,949 | |
2025 | 14,949 | |
2026 | 14,949 | |
2027 | 14,949 | |
2028 | 3,052 | |
Maturities for contractual obligations | ||
2024 | 384,426 | |
2025 | 357,627 | |
2026 | 339,272 | |
2027 | 317,589 | |
2028 | $ 347,742 | |
Weighted average interest rate on short-term borrowings (as a percent) | 5.72% | 4.84% |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | $ 12,096,552 | $ 11,940,359 |
Long-term debt | ||
Maturities for long-term debt | ||
2024 | 375,075 | |
2025 | 347,214 | |
2026 | 327,677 | |
2027 | 304,677 | |
2028 | $ 345,589 | |
Maturities for contractual obligations | ||
Weighted average interest rate on long-term debt | 3.89% | 3.78% |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | $ 12,096,552 | $ 11,940,359 |
Unamortized Debt Issuance Costs and Debt Discounts | 120,560 | 114,142 |
Finance Leases | ||
Maturities for finance leases | ||
2024 | 9,351 | |
2025 | 10,413 | |
2026 | 11,595 | |
2027 | 12,912 | |
2028 | 2,153 | |
FFB | Long-term debt | ||
Maturities for long-term debt | ||
2024 | 311,565 | |
2025 | 284,714 | |
2026 | 265,177 | |
2027 | 242,177 | |
2028 | 283,089 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 6,841,352 | 7,084,148 |
Unamortized Debt Issuance Costs and Debt Discounts | 51,083 | 52,690 |
FMBs | Long-term debt | ||
Maturities for long-term debt | ||
2024 | 63,510 | |
2025 | 62,500 | |
2026 | 62,500 | |
2027 | 62,500 | |
2028 | 62,500 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 4,551,010 | 4,152,021 |
Unamortized Debt Issuance Costs and Debt Discounts | 60,987 | 52,480 |
PCRBs | Long-term debt | ||
Maturities for long-term debt | ||
2024 | 0 | |
2025 | 0 | |
2026 | 0 | |
2027 | 0 | |
2028 | 0 | |
Long-term debt outstanding and the associated unamortized debt issuance costs and debt discounts | ||
Principal | 704,190 | 704,190 |
Unamortized Debt Issuance Costs and Debt Discounts | $ 8,490 | $ 8,972 |
Debt - Department of Energy Loa
Debt - Department of Energy Loan Guarantee (Details) | 12 Months Ended | ||||
Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Mar. 22, 2019 USD ($) | Feb. 20, 2014 USD ($) note | |
Debt | |||||
Repayments of long-term debt | $ 358,477,000 | $ 397,162,000 | $ 468,577,000 | ||
Loan Guarantee Agreement | |||||
Debt | |||||
Term of debt | 5 years | ||||
Period of cessation of construction activities which would result in prepayment of outstanding principal | 12 months | ||||
Period of failure to fund operation and maintenance expenses which would result in prepayment of outstanding principal | 12 months | ||||
Long-term debt | Department of Energy guarantee | |||||
Debt | |||||
Aggregate borrowings including capitalized interest | $ 4,177,967,442 | ||||
Long-term debt | FFB | |||||
Debt | |||||
Number of future advance promissory notes | note | 2 | ||||
Maximum borrowing capacity | $ 1,619,679,706 | $ 3,057,069,461 | |||
Maximum borrowing capacity designated for capitalized interest | 4,633,028,088 | ||||
Repayments of long-term debt | $ 455,060,646 | ||||
Long-term debt | FFB | Department of Energy guarantee | Services Agreement | |||||
Debt | |||||
Guarantee obligations, maximum exposure received | $ 4,676,749,167 |
Debt - Rural Utilities Service
Debt - Rural Utilities Service Guaranteed Loans (Details) - Long-term debt - FFB - Rural Utilities Service Guaranteed Loans - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended |
Feb. 29, 2024 | Dec. 31, 2023 | |
Debt | ||
Advances received on loans | $ 70,272 | |
Subsequent Event | ||
Debt | ||
Advances received on loans | $ 6,067 |
Debt - Credit Facilities (Detai
Debt - Credit Facilities (Details) | Dec. 31, 2023 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 | $ 611,000,000 |
Debt - First Mortgage Bonds (De
Debt - First Mortgage Bonds (Details) $ in Thousands | Dec. 05, 2023 USD ($) |
Debt | |
Repayments of Commercial Paper | $ 390,612 |
Mortgage Bonds | Series 2022A First Mortgage Bonds | |
Debt | |
Principal amount | $ 400,000 |
Interest rate (as a percent) | 6.20% |
Debt - Pollution Control Revenu
Debt - Pollution Control Revenue Bonds (Details) $ in Thousands | Feb. 01, 2023 USD ($) |
Municipal bonds | Series 2017 Pollution Control Revenue Bonds | |
Debt | |
Principal amount | $ 99,785 |
Electric plant, construction _3
Electric plant, construction and related agreements - Electric plant (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Public Utility Property Plant and Equipment | ||
Investment | $ 14,414,830 | $ 9,569,359 |
Accumulated Depreciation | (5,418,738) | (5,183,589) |
Total construction work in progress | 3,294,641 | 7,716,035 |
Plant acquisition adjustments | $ 290,725 | 280,396 |
Vogtle Units No. 1 & No. 2 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 30% | |
Investment | $ 3,035,806 | 3,024,112 |
Accumulated Depreciation | $ (1,948,158) | (1,916,942) |
Vogtle Units No. 3 & No. 4 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 30% | |
Investment | $ 4,771,526 | 58,189 |
Accumulated Depreciation | (43,418) | (8,627) |
Total construction work in progress | $ 3,128,720 | 7,583,291 |
Hatch Units No. 1 & No. 2 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 30% | |
Investment | $ 1,019,809 | 991,852 |
Accumulated Depreciation | $ (559,001) | (533,771) |
Wansley Units No. 1 & No. 2 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 30% | |
Investment | $ 24,710 | 20,312 |
Accumulated Depreciation | $ (27,152) | (15,337) |
Scherer Unit No. 1 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 60% | |
Investment | $ 1,372,241 | 1,378,904 |
Accumulated Depreciation | $ (660,580) | (636,799) |
Doyle | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 148,902 | 145,780 |
Accumulated Depreciation | $ (127,378) | (124,306) |
Rocky Mountain Units No. 1, No. 2 & No. 3 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 75% | |
Investment | $ 618,955 | 616,278 |
Accumulated Depreciation | $ (308,827) | (296,624) |
Hartwell | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 233,662 | 232,532 |
Accumulated Depreciation | $ (131,434) | (125,092) |
Hawk Road Energy Facility | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 272,416 | 269,837 |
Accumulated Depreciation | $ (79,985) | (74,685) |
Talbot | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 308,837 | 301,869 |
Accumulated Depreciation | $ (167,033) | (162,137) |
Chattahoochee | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 343,531 | 324,310 |
Accumulated Depreciation | $ (168,292) | (171,272) |
BC Smith Energy Facility | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 352,005 | 339,189 |
Accumulated Depreciation | $ (126,886) | (121,318) |
TA Smith Energy Facility | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 689,198 | 686,517 |
Accumulated Depreciation | $ (228,997) | (208,142) |
Washington County | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 171,034 | 170,432 |
Accumulated Depreciation | $ (92,498) | (88,585) |
Baconton | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 100% | |
Investment | $ 32,987 | 0 |
Accumulated Depreciation | (16,379) | 0 |
Transmission | ||
Public Utility Property Plant and Equipment | ||
Investment | 122,452 | 107,992 |
Accumulated Depreciation | (65,784) | (64,785) |
Other production | ||
Public Utility Property Plant and Equipment | ||
Investment | 101,061 | 106,424 |
Accumulated Depreciation | $ (60,710) | (65,922) |
Scherer Unit No. 2 | ||
Public Utility Property Plant and Equipment | ||
Ownership interest (as a percent) | 60% | |
Investment | $ 795,698 | 794,830 |
Accumulated Depreciation | (606,226) | (569,245) |
Environmental and other generation improvements | ||
Public Utility Property Plant and Equipment | ||
Total construction work in progress | $ 165,921 | $ 132,744 |
Electric plant, construction _4
Electric plant, construction and related agreements - Narrative (Details) $ in Millions | 12 Months Ended | ||||
Oct. 06, 2023 USD ($) | Oct. 05, 2023 USD ($) | Oct. 04, 2023 USD ($) | Feb. 18, 2019 USD ($) | Dec. 31, 2023 USD ($) unit MW | |
Public Utility Property Plant and Equipment | |||||
Expected monthly increase in cost | $ 20 | ||||
Vogtle Units No. 3 & No. 4 | |||||
Public Utility Property Plant and Equipment | |||||
Ownership interest (as a percent) | 30% | ||||
Remaining share paid by counterparty upon exercise of tender option (as a percent) | 100% | ||||
Percentage of disallowed costs excluded from adverse event triggers | 6% | ||||
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 | EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||||
Public Utility Property Plant and Equipment | |||||
Number of nuclear units | unit | 2 | ||||
Generating capacity (in megawatts) | MW | 1,100 | ||||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | |||||
Public Utility Property Plant and Equipment | |||||
Ownership share, generating capacity (in megawatts) | MW | 660 | ||||
Project budget | $ 8,200 | ||||
Proceeds from settlement agreement | 1,100 | ||||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | Minimum | |||||
Public Utility Property Plant and Equipment | |||||
Project budget | 8,300 | ||||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | Maximum | |||||
Public Utility Property Plant and Equipment | |||||
Project budget | 8,350 | ||||
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 | ||||
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 | $ 19,200 | ||||
Total construction costs paid | 241.2 | 384 | |||
Cost-sharing bands, total liability | 99 | ||||
Cost-sharing bands, financing costs | 5 | ||||
Payments for cost-sharing bands | 66.5 | $ 37.5 | |||
Total construction costs to be paid | $ 105.1 | $ 346.3 | |||
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 | Jointly Owned Nuclear Power Plant | Georgia Power | |||||
Public Utility Property Plant and Equipment | |||||
Incremental costs that exceed project budget, percent | 30% | ||||
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 | Maximum | Jointly Owned Nuclear Power Plant | Georgia Power | |||||
Public Utility Property Plant and Equipment | |||||
Incremental costs that exceed project budget, percent | 66% | ||||
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 No. 3 | |||||
Public Utility Property Plant and Equipment | |||||
Jointly owned utility plant, amount in service | $ 4,800 | ||||
Vogtle Unit No. 3 | Georgia Power | |||||
Public Utility Property Plant and Equipment | |||||
Nuclear production tax credit | $ 21.7 |
Employee benefit plans (Details
Employee benefit plans (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 USD ($) plan | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
401(k) plan | |||
Maximum percentage of eligible annual compensation that the employee can contribute subject to IRS limitations | 60% | ||
Percentage of employee's contribution percent matched | 75% | ||
Employer matching contribution, as a percent of employee's eligible compensation | 6% | ||
Amount of contributions to the matching feature of the 401(k) plan | $ 2,143 | $ 2,017 | $ 1,811 |
Contribution to employer retirement contribution feature (as a percent) | 11% | ||
Amount of contributions to the employer retirement contribution feature of the 401(k) plan | $ 5,655 | 5,098 | $ 4,527 |
Deferred compensation plans | |||
Number of deferred compensation plans | plan | 2 | ||
Deferred compensation plan assets | $ 5,723 | 4,616 | |
Deferred compensation liability | $ 5,723 | $ 4,616 |
Nuclear insurance (Details)
Nuclear insurance (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2023 USD ($) nuclearReactor | |
Nuclear insurance: | |
Maximum fund for public liability claims arising from a single nuclear incident under Price-Anderson Act | $ 16,200 |
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 | 166 |
Maximum aggregate amount that a reactor can assess in a calendar period for each incident | $ 25 |
Number of nuclear reactors in which entity has ownership interest | nuclearReactor | 6 |
Maximum deferred premium amount which the entity could be assessed per incident on the basis of its joint ownership interest in four nuclear reactors | $ 299 |
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 | $ 44 |
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 | 55 |
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) $ in Thousands | 12 Months Ended |
Dec. 31, 2023 USD ($) | |
Finance and Operating Leases | |
2024 | $ 16,862 |
2025 | 16,652 |
2026 | 16,361 |
2027 | 16,083 |
2028 | 4,078 |
Thereafter | $ 8,428 |
Scherer Unit No. 2 | |
Long-term Purchase Commitment [Line Items] | |
Ownership interest (as a percent) | 60% |
Coal | |
Long-term Purchase Commitment [Line Items] | |
2024 | $ 33,810 |
2025 | 15,938 |
2026 | 9,362 |
2027 | 0 |
2028 | 0 |
Thereafter | 0 |
Nuclear Fuel | |
Long-term Purchase Commitment [Line Items] | |
2024 | 95,520 |
2025 | 36,000 |
2026 | 32,250 |
2027 | 28,800 |
2028 | 28,500 |
Thereafter | 45,660 |
Gas Transportation | |
Long-term Purchase Commitment [Line Items] | |
2024 | 66,186 |
2025 | 67,368 |
2026 | 69,578 |
2027 | 73,075 |
2028 | 68,971 |
Thereafter | 835,212 |
Maintenance Agreements | |
Long-term Purchase Commitment [Line Items] | |
Cancellation obligation | 70,699 |
2024 | 57,749 |
2025 | 43,025 |
2026 | 15,736 |
2027 | 3,237 |
2028 | 46,964 |
Thereafter | 269,196 |
Asset Retirement Obligations | |
Long-term Purchase Commitment [Line Items] | |
2024 | 51,378 |
2025 | 39,673 |
2026 | 45,923 |
2027 | 59,885 |
2028 | 71,267 |
Thereafter | $ 5,065,526 |
Contingencies and Regulatory _2
Contingencies and Regulatory Matters (Details) | 12 Months Ended | 24 Months Ended | |||
Jan. 09, 2023 complaint | Feb. 07, 2022 complaint | Oct. 08, 2021 complaint | Dec. 31, 2023 plaintiff | Sep. 30, 2023 complaint | |
Contingencies and Regulatory Matters: | |||||
Number of plaintiffs | plaintiff | 48 | ||||
Number of petitions filed by parties | complaint | 1 | 4 | 3 | 8 |
Plant Acquisitions - Narrative
Plant Acquisitions - Narrative (Details) $ in Thousands | 12 Months Ended | |||
Aug. 22, 2023 generatingUnit MW | May 25, 2023 USD ($) generatingUnit MW | Dec. 31, 2023 | Feb. 29, 2024 USD ($) | |
Plant Acquisition [Line Items] | ||||
Number of generating units | generatingUnit | 4 | |||
Baconton | ||||
Plant Acquisition [Line Items] | ||||
Remaining life of the plant | 14 years | |||
Natural Gas Processing Plant | Baconton | ||||
Plant Acquisition [Line Items] | ||||
Number of generating units acquired | generatingUnit | 1 | |||
Generating unit, megawatts | MW | 188 | |||
Generating capacity (in megawatts) | MW | 45 | |||
Consideration transferred | $ | $ 16,743 | |||
Transaction costs | $ | $ 746 | |||
Natural Gas Processing Plant | Baconton | Subsequent Event | ||||
Plant Acquisition [Line Items] | ||||
Principal amount | $ | $ 17,500 | |||
Walton County Plant | ||||
Plant Acquisition [Line Items] | ||||
Number of generating units acquired | generatingUnit | 3 | |||
Generating unit, megawatts | MW | 465 |
Plant Acquisitions - Identifiab
Plant Acquisitions - Identifiable Assets Acquired and Liabilities Assumed (Details) - Natural Gas Processing Plant - Baconton $ in Thousands | Dec. 20, 2022 USD ($) |
Plant Acquisition [Line Items] | |
Electric plant in service, net | $ 16,450 |
Other current assets | 323 |
Other current liabilities | (30) |
Total identifiable net assets | $ 16,743 |
Quarterly financial data (una_3
Quarterly financial data (unaudited) (Details) - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended | |||||||||
Dec. 31, 2023 | Sep. 30, 2023 | Jun. 30, 2023 | Mar. 31, 2023 | Dec. 31, 2022 | Sep. 30, 2022 | Jun. 30, 2022 | Mar. 31, 2022 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Quarterly Financial Data [Abstract] | |||||||||||
Operating revenues | $ 460,567 | $ 500,776 | $ 389,389 | $ 389,453 | $ 472,302 | $ 704,265 | $ 533,128 | $ 420,442 | |||
Operating margin | 77,756 | 92,317 | 49,987 | 57,006 | 17,384 | 64,553 | 54,269 | 57,845 | $ 277,066 | $ 194,051 | $ 194,381 |
Net margin | $ (4,161) | $ 27,127 | $ 18,414 | $ 24,410 | $ (10,540) | $ 32,097 | $ 18,167 | $ 21,980 |