Cover Page
Cover Page | 6 Months Ended |
Jun. 30, 2023 shares | |
Cover [Abstract] | |
Document Type | 10-Q |
Document Quarterly Report | true |
Document Period End Date | Jun. 30, 2023 |
Document Transition Report | false |
Entity File Number | 333-192954 |
Entity Registrant Name | OGLETHORPE POWER CORP |
Entity Incorporation, State or Country Code | GA |
Entity Tax Identification Number | 58-1211925 |
Entity Address, Address Line One | 2100 East Exchange Place |
Entity Address, City or Town | Tucker |
Entity Address, State or Province | GA |
Entity Address, Postal Zip Code | 30084-5336 |
City Area Code | 770 |
Local Phone Number | 270-7600 |
Entity Current Reporting Status | Yes |
Entity Interactive Data Current | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Small Business | false |
Entity Emerging Growth Company | false |
Entity Shell Company | false |
Entity Common Stock, Shares Outstanding | 0 |
Entity Central Index Key | 0000788816 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Document Fiscal Year Focus | 2023 |
Document Fiscal Period Focus | Q2 |
Consolidated Balance Sheets (Un
Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands | Jun. 30, 2023 | Dec. 31, 2022 |
Electric plant: | ||
In service | $ 9,445,734 | $ 9,266,627 |
Right-of-use assets—finance leases | 302,732 | 302,732 |
Less: Accumulated provision for depreciation | (5,288,246) | (5,183,589) |
Electric plant in service, net | 4,460,220 | 4,385,770 |
Nuclear fuel, at amortized cost | 397,574 | 388,303 |
Construction work in progress | 8,057,892 | 7,716,035 |
Total electric plant | 12,915,686 | 12,490,108 |
Investments and funds: | ||
Nuclear decommissioning trust fund | 598,357 | 540,716 |
Investment in associated companies | 78,320 | 78,937 |
Long-term investments | 657,779 | 669,479 |
Other | 33,503 | 32,561 |
Total investments and funds | 1,367,959 | 1,321,693 |
Current assets: | ||
Cash and cash equivalents | 459,368 | 595,381 |
Restricted cash and short-term investments | 5,600 | 104,431 |
Short-term investments | 90,147 | 61,702 |
Receivables | 179,775 | 220,015 |
Inventories, at average cost | 322,255 | 297,951 |
Prepayments and other current assets | 31,699 | 51,409 |
Total current assets | 1,088,844 | 1,330,889 |
Deferred charges and other assets: | ||
Regulatory assets | 1,198,819 | 1,212,305 |
Prepayments to Georgia Power Company | 6,260 | 20,873 |
Other | 51,334 | 113,502 |
Total deferred charges | 1,256,413 | 1,346,680 |
Total assets | 16,628,902 | 16,489,370 |
Capitalization: | ||
Patronage capital and membership fees | 1,234,951 | 1,192,127 |
Long-term debt | 11,350,650 | 11,512,513 |
Obligation under finance leases | 48,388 | 52,937 |
Obligation under Rocky Mountain transactions | 28,888 | 27,945 |
Other | 1,825 | 2,256 |
Total capitalization | 12,664,702 | 12,787,778 |
Current liabilities: | ||
Long-term debt and finance leases due within one year | 315,213 | 322,102 |
Short-term borrowings | 1,064,888 | 655,650 |
Accounts payable | 129,252 | 203,705 |
Accrued interest | 82,753 | 105,452 |
Member power bill prepayments, current | 44,047 | 54,443 |
Other current liabilities | 83,299 | 153,941 |
Total current liabilities | 1,719,452 | 1,495,293 |
Deferred credits and other liabilities: | ||
Asset retirement obligations | 1,458,257 | 1,343,743 |
Member power bill prepayments, non-current | 51,255 | 53,877 |
Regulatory liabilities | 719,364 | 792,190 |
Other | 15,872 | 16,489 |
Total deferred credits and other liabilities | 2,244,748 | 2,206,299 |
Total equity and liabilities | $ 16,628,902 | $ 16,489,370 |
Consolidated Statements of Reve
Consolidated Statements of Revenues and Expenses (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Operating revenues: | ||||
Total operating revenues | $ 389,389 | $ 533,128 | $ 778,842 | $ 953,570 |
Operating expenses: | ||||
Fuel | 132,468 | 263,121 | 265,636 | 428,605 |
Production | 99,412 | 113,387 | 192,879 | 209,167 |
Depreciation and amortization | 73,015 | 70,830 | 145,689 | 141,756 |
Purchased power | 17,785 | 17,661 | 35,415 | 34,536 |
Accretion | 16,722 | 13,860 | 32,230 | 27,392 |
Total operating expenses | 339,402 | 478,859 | 671,849 | 841,456 |
Operating margin | 49,987 | 54,269 | 106,993 | 112,114 |
Other income: | ||||
Investment income | 17,943 | 12,825 | 34,325 | 24,672 |
Other | 2,909 | 3,095 | 5,834 | 6,125 |
Total other income | 20,852 | 15,920 | 40,159 | 30,797 |
Interest charges: | ||||
Interest expense | 128,384 | 111,595 | 252,091 | 216,264 |
Allowance for debt funds used during construction | (78,591) | (62,497) | (153,021) | (119,270) |
Amortization of debt discount and expense | 2,632 | 2,924 | 5,258 | 5,770 |
Net interest charges | 52,425 | 52,022 | 104,328 | 102,764 |
Net margin | 18,414 | 18,167 | 42,824 | 40,147 |
Members | ||||
Operating revenues: | ||||
Total operating revenues | 365,496 | 478,782 | 753,149 | 896,231 |
Non-Members | ||||
Operating revenues: | ||||
Total operating revenues | $ 23,893 | $ 54,346 | $ 25,693 | $ 57,339 |
Consolidated Statements of Patr
Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||||
Jun. 30, 2023 | Mar. 31, 2023 | Jun. 30, 2022 | Mar. 31, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | |
Increase (Decrease) in Members' Capital | ||||||
Net margin | $ 18,414 | $ 18,167 | $ 42,824 | $ 40,147 | ||
Patronage Capital and Membership Fees | ||||||
Increase (Decrease) in Members' Capital | ||||||
Beginning balance | 1,216,537 | $ 1,192,127 | 1,152,403 | $ 1,130,423 | 1,192,127 | 1,130,423 |
Net margin | 18,414 | 24,410 | 18,167 | 21,980 | ||
Ending balance | $ 1,234,951 | $ 1,216,537 | $ 1,170,570 | $ 1,152,403 | $ 1,234,951 | $ 1,170,570 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2023 | Jun. 30, 2022 | |
Cash flows from operating activities: | ||
Net margin | $ 42,824 | $ 40,147 |
Adjustments to reconcile net margin to net cash provided by operating activities: | ||
Depreciation and amortization, including nuclear fuel | 196,729 | 203,299 |
Accretion cost | 32,230 | 27,392 |
Amortization of deferred gains | (894) | (894) |
Allowance for equity funds used during construction | (307) | (291) |
Deferred outage costs | (22,985) | (23,107) |
(Gain) loss on sale of investments | (9,989) | 18,467 |
Regulatory deferral of costs associated with nuclear decommissioning | (5,371) | (33,956) |
Other | (723) | 642 |
Change in operating assets and liabilities: | ||
Receivables | 34,021 | (123,344) |
Inventories | (23,876) | (21,933) |
Prepayments and other current assets | (5,886) | (20,532) |
Accounts payable | (98,977) | 17,584 |
Accrued interest | (22,699) | (16,253) |
Accrued taxes | (19,844) | 35,915 |
Other current liabilities | (55,884) | 64,929 |
Member power bill prepayments | (13,018) | (12,478) |
Rate management program (disbursements) collections | (25,185) | 13,960 |
Total adjustments | (42,658) | 129,400 |
Net cash provided by operating activities | 166 | 169,547 |
Cash flows from investing activities: | ||
Property additions | (495,134) | (526,406) |
Plant acquisition | (16,743) | 0 |
Activity in nuclear decommissioning trust fund—Purchases | (217,394) | (199,140) |
Activity in nuclear decommissioning trust fund - Proceeds | 213,108 | 195,557 |
Decrease in restricted investments | 74,031 | 184,812 |
Activity in other long-term investments—Purchases | (95,750) | (134,310) |
Activity in other long-term investments - Proceeds | 98,756 | 102,982 |
Other | 20,100 | 2,615 |
Net cash used in investing activities | (419,026) | (373,890) |
Cash flows from financing activities: | ||
Long-term debt proceeds | 38,401 | 792,503 |
Long-term debt payments | (213,972) | (256,747) |
Increase (decrease) in short-term borrowings, net | 409,237 | (334,689) |
Other | 24,381 | 14,493 |
Net cash provided by financing activities | 258,047 | 215,560 |
Net (decrease) increase in cash, cash equivalents and restricted cash | (160,813) | 11,217 |
Cash, cash equivalents and restricted cash at beginning of period | 625,781 | 581,150 |
Cash, cash equivalents and restricted cash at end of period | 464,968 | 592,367 |
Cash paid for— | ||
Interest (net of amounts capitalized) | 120,826 | 112,365 |
Supplemental disclosure of non-cash investing and financing activities: | ||
Change in asset retirement obligations | 87,509 | 0 |
Accrued property additions at end of period | 92,532 | 64,476 |
Bond purchase fund included in cash, cash equivalents and restricted cash at end of period | $ 0 | $ 30,975 |
General
General | 6 Months Ended |
Jun. 30, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
General | General. The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, our financial condition and results of operations for the three-month and six-month periods ended June 30, 2023 and 2022. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) depreciation rates, such as determining the depreciable service lives. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2022, as filed with the SEC. The results of operations for the three-month and six-month periods ended June 30, 2023 are not necessarily indicative of results to be expected for the full year. As noted in our 2022 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. See "Notes to Consolidated Financial Statements" in our 2022 Form 10-K. During the quarter ended June 30, 2023, we identified a misstatement in the amounts presented in the net cash flows (used in) provided by operating activities and net cash flow used in investing activities presented in the unaudited Consolidated Statement of Cash Flows for the three months ended March 31, 2023. The error resulted in a $26,100,000 understatement of the depreciation and amortization, including nuclear fuel adjustment included in adjustments to reconcile net margin to net cash provided by operating activities section of the cash flows from operating activities and an offsetting $26,100,000 understatement of cash used for property additions included in cash flows from investing activities. After correction of this misstatement the balances presented for the quarter ended March 31, 2023 were as follows: (dollars in thousands) Depreciation and amortization, including nuclear fuel $ 92,645 Net cash used in operating activities (64,810) Property additions (285,233) Net cash used in investing activities (200,535) The errors identified did not have any impact on the overall change in cash, cash equivalents and restricted cash and did not affect the unaudited Consolidated Balance Sheets or the unaudited Consolidated Statements of Revenues and Expenses for any periods presented. The misstatement was corrected in the unaudited Consolidated Statements of Cash Flows for the six months ended June 30, 2023 and we do not believe the error is material to the consolidated financial statements taken as a whole. |
Fair Value
Fair Value | 6 Months Ended |
Jun. 30, 2023 | |
Fair Value Disclosures [Abstract] | |
Fair Value | Fair Value. Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: • Level 1. Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded. • Level 2. Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs. • Level 3. Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques: 1. Market approach. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs. 2. Income approach. The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. 3. Cost approach. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2023 and December 31, 2022. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs June 30, 2023 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 217,632 $ 217,632 $ — $ — International equity trust 128,828 — 128,828 — Corporate bonds and debt 67,669 — 67,614 55 US Treasury securities 54,112 54,112 — — Mortgage backed securities 39,314 — 39,314 — Domestic mutual funds 73,435 73,435 — — Federal agency securities 7,565 — 7,565 — International mutual funds 717 — 717 — Non-US Gov't bonds & private placements 2,730 — 2,730 — Other 6,355 6,054 301 — Long-term investments: International equity trust 38,629 — 38,629 — Corporate bonds and debt 12,273 — 12,273 — US Treasury securities 16,803 16,803 — — Mortgage backed securities 13,495 — 13,495 — Domestic mutual funds 334,003 334,003 — — Treasury STRIPS 240,747 — 240,747 — Non-US Gov't bonds & private placements 1,751 — 1,751 — Other 78 78 — — Short-term investments: Treasury STRIPS 90,147 — 90,147 — Natural gas swaps 49,235 — 49,235 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2022 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 204,129 $ 204,129 $ — $ — International equity trust 111,266 — 111,266 — Corporate bonds and debt 60,806 — 60,788 18 US Treasury securities 49,775 49,775 — — Mortgage backed securities 41,210 — 41,210 — Domestic mutual funds 57,348 57,348 — — Federal agency securities 2,037 — 2,037 — Non-US Gov't bonds & private placements 2,890 — 2,890 — International mutual funds 653 — 653 — Other 10,602 10,602 — — Long-term investments: International equity trust 33,606 — 33,606 — Corporate bonds and debt 10,473 — 10,473 — US Treasury securities 15,488 15,488 — — Mortgage backed securities 12,113 — 12,113 — Domestic mutual funds 302,302 302,302 — — Treasury STRIPS 293,281 — 293,281 — Non-US Gov't bonds & private placements 1,976 — 1,976 — Other 240 240 — — Short-term investments: Treasury STRIPS 61,702 — 61,702 — Natural gas swaps 131,804 — 131,804 — The Level 2 investments above in corporate bonds and debt, federal agency securities, and mortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs at or near the valuation date. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period. The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchange traded. Although these securities may be liquid and priced daily, their inputs are not observable. The estimated fair values of our long-term debt, including current maturities at June 30, 2023 and December 31, 2022 were as follows: 2023 2022 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 11,768,875 $ 10,214,166 $ 11,940,359 $ 10,194,954 The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of June 30, 2023 and December 31, 2022 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. For cash and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury. |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Derivative Instruments | Derivative Instruments. We use commodity derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statement of cash flows. We are exposed to credit risk as a result of entering into these arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions. It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of June 30, 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 June 30, 2023 and December 31, 2022, the estimated fair values of our natural gas contracts were net assets of approximately $49,235,000 and $131,804,000, respectively. At June 30, 2023 and December 31, 2022, one of our counterparties was required to post credit collateral totaling $5,600,000 and $30,400,000 , respectively, under our natural gas swap agreements. Such posted collateral is classified as restricted cash and included in the Restricted cash and short-term investments line item within our unaudited consolidated balance sheets. The following table reflects the notional volume of our natural gas derivatives as of June 30, 2023 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2023 19.8 2024 30.5 2025 25.0 2026 20.3 2027 7.7 Total 103.3 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2023 and December 31, 2022. Balance Sheet Location Fair Value 2023 2022 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 9,688 $ 35,285 Natural gas swaps Other deferred charges $ 44,681 $ 99,725 Liabilities: Natural gas swaps Other current liabilities $ 5,115 $ 3,206 Natural gas swaps Other deferred credits $ 19 $ — The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and six months ended June 30, 2023 and 2022. Statement of Three Months Ended June 30, Six Months Ended 2023 2022 2023 2022 (dollars in thousands) Natural gas swaps gains Fuel $ 5 $ 42,563 $ 140 $ 50,641 Natural gas swaps losses Fuel (7,207) (203) (16,604) (282) Total $ (7,202) $ 42,360 $ (16,464) $ 50,359 The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at June 30, 2023 and December 31, 2022. Balance Sheet Location 2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 49,235 $ 131,804 Total $ 49,235 $ 131,804 |
Investments Securities
Investments Securities | 6 Months Ended |
Jun. 30, 2023 | |
Investments, Debt and Equity Securities [Abstract] | |
Investment Securities | Investment Securities. Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. The following tables summarize debt and equity securities as of June 30, 2023 and December 31, 2022. Gross Unrealized (dollars in thousands) June 30, 2023 Cost Gains Losses Fair Equity $ 330,886 $ 209,975 $ (6,023) $ 534,838 Debt 843,576 1,057 (39,246) 805,387 Other 6,006 59 (7) 6,058 Total $ 1,180,468 $ 211,091 $ (45,276) $ 1,346,283 Gross Unrealized (dollars in thousands) December 31, 2022 Cost Gains Losses Fair Equity $ 323,907 $ 159,445 $ (8,949) $ 474,403 Debt 833,035 372 (46,369) 787,038 Other 10,445 20 (9) 10,456 Total $ 1,167,387 $ 159,837 $ (55,327) $ 1,271,897 |
Recently Issued or Adopted Acco
Recently Issued or Adopted Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2023 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
Recently Issued or Adopted Accounting Pronouncements | Recently Issued or Adopted Accounting Pronouncements. As of June 30, 2023, we have implemented all applicable new accounting standards and updates issued by the Financial Accounting Standards Board (FASB) that were in effect. There were no applicable standards or updates during the six months ended June 30, 2023 that had a material impact on our consolidated financial statements. |
Revenue Recognition
Revenue Recognition | 6 Months Ended |
Jun. 30, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenue Recognition | Revenue Recognition. As an electric membership cooperative, our principal business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated to pay us for capacity and energy we furnish under the wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. As of June 30, 2023 and December 31, 2022, we did not have any significant long-term contracts with non-members. The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. For information regarding regulatory accounting, see Note J. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are generally recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues are billed and recognized in accordance with the terms of the associated contract. We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note K. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. For the six-month periods ended June 30, 2023 and 2022, we provided approximately 68% and 58% of our members' energy requirements, respectively. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2023, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our unaudited consolidated balance sheets. As of June 30, 2023 and June 30, 2022, we recognized refund liabilities totaling $4,000,000 and $5,000,000, respectively. As of December 31, 2022, we recognized refund liabilities totaling $28,471,000. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members for the three and six months ended June 30, 2023 and 2022 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2023 2022 2023 2022 Capacity revenues $ 234,183 $ 241,841 $ 476,227 $ 485,132 Energy revenues 131,313 236,941 276,922 411,099 Total $ 365,496 $ 478,782 $ 753,149 $ 896,231 Member energy requirements supplied 71 % 59 % 68 % 58 % Receivables from contracts with our members at June 30, 2023 and December 31, 2022 were $139,422,000 and $187,401,000, respectively. Sales to non-members during the three and six months ended June 30, 2023 and 2022 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2023 2022 2023 2022 Energy revenues $ 20,269 $ 54,346 $ 21,306 $ 57,339 Capacity revenues 3,624 — 4,387 — Total $ 23,893 $ 54,346 $ 25,693 $ 57,339 Receivables from the sale of electricity to non-members were $6,951,000 at June 30, 2023 and $8,787,000 at December 31, 2022 and are primarily from the sale of the Bobby C. Smith Jr. Energy Facility's deferring members’ output. In May 2023, our Effingham Energy Facility was renamed the Bobby C. Smith Jr. Energy Facility in honor of our late board chairman. The remainder of our receivables is primarily related to transactions with affiliated companies and investment income which were $32,793,000 and $13,834,000 at June 30, 2023 and December 31, 2022, respectively. Energy revenues from non-members for the three and six months ended June 30, 2023 were primarily from the sale of the Bobby C. Smith Jr. deferring members' output into the wholesale market. For the three and six months ended June 30, 2023, we recognized capacity revenues from non-members related to the two units we acquired at the Washington County Power Plant in December 2022. For additional information regarding the Washington County acquisition, see Note 14 in our 2022 Form 10-K. Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members and have not had a history of any write-offs from non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs associated with the construction of Vogtle Units No. 3 and No. 4, on a current basis, that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. Under this program, amounts billed to participating members during the six months ended June 30, 2023 and 2022 were $4,050,000 and $9,440,000, respectively. The cumulative amount billed since inception of the program totaled $130,482,000. |
Leases
Leases | 6 Months Ended |
Jun. 30, 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. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through October 31, 2026. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (275,512) (272,876) Total finance lease assets $ 27,220 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 48,388 $ 52,937 Long-term debt and finance leases due within one year 8,861 8,398 Total finance lease liabilities $ 57,249 $ 61,335 Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 2,734 $ 3,326 Total operating lease assets $ 2,734 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,825 $ 2,256 Other current liabilities 1,003 1,164 Total operating lease liabilities $ 2,828 $ 3,420 Three months ended Six months ended Lease Cost Classification June 30, 2023 June 30, 2022 June 30, 2023 June 30, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,100 $ 1,886 $ 4,199 $ 3,771 Interest on lease liabilities Interest expense 1,638 1,852 3,276 3,704 Operating lease cost: Inventory (1) & production expense 328 222 657 444 Total leased cost $ 4,066 $ 3,960 $ 8,132 $ 7,919 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. June 30, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.72 5.94 Operating leases 6.87 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % Six months ended June 30, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,389 $ 3,806 Operating cash flows from operating leases $ 657 $ 444 Financing cash flows from finance leases $ 4,086 $ 3,669 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of June 30, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 7,475 $ 667 $ 8,142 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,685 868 11,553 Total lease payments $ 77,956 $ 3,448 $ 81,404 Less: imputed interest (20,707) (620) (21,327) Present value of lease liabilities $ 57,249 $ 2,828 $ 60,077 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and six months ended June 30, 2023 and 2022 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2023 2022 2023 2022 (dollars in thousands) Lease income $ 1,691 $ 1,669 $ 3,376 $ 3,314 |
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. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through October 31, 2026. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (275,512) (272,876) Total finance lease assets $ 27,220 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 48,388 $ 52,937 Long-term debt and finance leases due within one year 8,861 8,398 Total finance lease liabilities $ 57,249 $ 61,335 Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 2,734 $ 3,326 Total operating lease assets $ 2,734 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,825 $ 2,256 Other current liabilities 1,003 1,164 Total operating lease liabilities $ 2,828 $ 3,420 Three months ended Six months ended Lease Cost Classification June 30, 2023 June 30, 2022 June 30, 2023 June 30, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,100 $ 1,886 $ 4,199 $ 3,771 Interest on lease liabilities Interest expense 1,638 1,852 3,276 3,704 Operating lease cost: Inventory (1) & production expense 328 222 657 444 Total leased cost $ 4,066 $ 3,960 $ 8,132 $ 7,919 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. June 30, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.72 5.94 Operating leases 6.87 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % Six months ended June 30, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,389 $ 3,806 Operating cash flows from operating leases $ 657 $ 444 Financing cash flows from finance leases $ 4,086 $ 3,669 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of June 30, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 7,475 $ 667 $ 8,142 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,685 868 11,553 Total lease payments $ 77,956 $ 3,448 $ 81,404 Less: imputed interest (20,707) (620) (21,327) Present value of lease liabilities $ 57,249 $ 2,828 $ 60,077 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and six months ended June 30, 2023 and 2022 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2023 2022 2023 2022 (dollars in thousands) Lease income $ 1,691 $ 1,669 $ 3,376 $ 3,314 |
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. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through October 31, 2026. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (275,512) (272,876) Total finance lease assets $ 27,220 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 48,388 $ 52,937 Long-term debt and finance leases due within one year 8,861 8,398 Total finance lease liabilities $ 57,249 $ 61,335 Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 2,734 $ 3,326 Total operating lease assets $ 2,734 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,825 $ 2,256 Other current liabilities 1,003 1,164 Total operating lease liabilities $ 2,828 $ 3,420 Three months ended Six months ended Lease Cost Classification June 30, 2023 June 30, 2022 June 30, 2023 June 30, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,100 $ 1,886 $ 4,199 $ 3,771 Interest on lease liabilities Interest expense 1,638 1,852 3,276 3,704 Operating lease cost: Inventory (1) & production expense 328 222 657 444 Total leased cost $ 4,066 $ 3,960 $ 8,132 $ 7,919 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. June 30, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.72 5.94 Operating leases 6.87 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % Six months ended June 30, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,389 $ 3,806 Operating cash flows from operating leases $ 657 $ 444 Financing cash flows from finance leases $ 4,086 $ 3,669 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — Maturity analysis of our finance and operating lease liabilities as of June 30, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 7,475 $ 667 $ 8,142 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,685 868 11,553 Total lease payments $ 77,956 $ 3,448 $ 81,404 Less: imputed interest (20,707) (620) (21,327) Present value of lease liabilities $ 57,249 $ 2,828 $ 60,077 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and six months ended June 30, 2023 and 2022 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2023 2022 2023 2022 (dollars in thousands) Lease income $ 1,691 $ 1,669 $ 3,376 $ 3,314 |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters | 6 Months Ended |
Jun. 30, 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 quarterly report, this case has approximately 48 plaintiffs. Eight additional complaints, three on October 8, 2021, four on February 7, 2022, and one on January 9, 2023, were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs 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 and the announced retirement of Unit No. 3 at the end of 2028. 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. |
Restricted Cash and Investments
Restricted Cash and Investments | 6 Months Ended |
Jun. 30, 2023 | |
Restricted Investments Note [Abstract] | |
Restricted Cash and Investments | Restricted Cash and Investments. Restricted investments consisted of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that were held by the U.S. Treasury, acting through the Federal Financing Bank. At December 31, 2022, we had restricted investments totaling $74,031,000, all of which were classified as current. During the three-month period ended March 31, 2023, we utilized all of our restricted investments for scheduled Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. No restricted investments were held at June 30, 2023. Restricted cash consists of collateral posted by our counterparties under our natural gas swap agreements. The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the unaudited consolidated balance sheets that sum to the total of the same such amounts reported in the unaudited consolidated statements of cash flows. Classification Six months ended June 30, 2023 June 30, 2022 (dollars in thousands) Cash and cash equivalents $ 459,368 $ 476,792 Bond purchase fund — 30,975 Restricted cash included in restricted cash and short-term investments 5,600 84,600 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 464,968 $ 592,367 |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 6 Months Ended |
Jun. 30, 2023 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Regulatory Assets and Liabilities | Regulatory Assets and Liabilities. We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members. The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members. The following regulatory assets and liabilities are reflected on the consolidated balance sheets as of June 30, 2023 and December 31, 2022. 2023 2022 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 27,485 $ 29,494 Amortization of financing leases(b) 30,344 31,908 Outage costs(c) 36,043 29,317 Asset retirement obligations—Ashpond and other(l) 376,122 353,212 Asset retirement obligations—Nuclear(l) — 32,192 Depreciation expense - Plant Vogtle(d) 34,838 35,549 Depreciation expense - Plant Wansley(e) 351,734 361,784 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,669 54,701 Interest rate options cost(g) 139,539 136,827 Deferral of effects on net margin—Smith Energy Facility(h) 133,758 136,730 Other regulatory assets(o) 13,287 10,591 Total Regulatory Assets $ 1,198,819 $ 1,212,305 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 34,296 $ 35,580 Deferral of effects on net margin—Hawk Road Energy Facility(h) 16,328 16,636 Deferral of effects on net margin—Bobby C. Smith Jr. Energy Facility(p) 6,941 14,825 Major maintenance reserve(j) 94,395 74,584 Amortization of financing leases(b) 4,108 5,557 Deferred debt service adder(k) 162,516 154,514 Asset retirement obligations—Nuclear(l) 19,520 — Revenue deferral plan(m) 330,949 357,460 Natural gas hedges(n) 49,235 131,804 Other regulatory liabilities(o) 1,076 1,230 Total Regulatory Liabilities $ 719,364 $ 792,190 Net Regulatory Assets $ 479,455 $ 420,115 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 21 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Represents the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which occurred on August 31, 2022. Amortization commenced upon the retirement of Plant Wansley and will end no later than December 31, 2040. (f) Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization commenced in August 2023 after Vogtle Unit No. 3 was placed in service on July 31, 2023. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (m) Deferred revenues under a rate management program that allowed for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings, per each members' election, over the subsequent five-year period. (n) Represents the deferral of unrealized gains on natural gas contracts. (o) The amortization periods for other regulatory assets range up to 27 years and the amortization periods of other regulatory liabilities range up to 4 years. (p) Effects on net margin for the Bobby C. Smith Jr. Energy Facility that are being deferred until on or before January 2026 and will be amortized over the remaining life of the plant. |
Member Power Bill Prepayments
Member Power Bill Prepayments | 6 Months Ended |
Jun. 30, 2023 | |
Member Power Bill Prepayments | |
Member Power Bill Prepayments | Member Power Bill Prepayments. We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through December 2028, with the majority of the balance scheduled to be credited by the end of 2024. |
Debt
Debt | 6 Months Ended |
Jun. 30, 2023 | |
Debt Disclosure [Abstract] | |
Debt | Debt. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a term loan facility (the Facility) under which we borrowed a total of $4,633,028,088. We received our final advance under the Facility in December 2022. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes began on February 20, 2020. As of June 30, 2023, we have repaid $393,577,094 of principal on the FFB Notes and the aggregate Department of Energy-guaranteed borrowings outstanding, including capitalized interest, totaled $4,239,450,994. 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 Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve b) Rural Utilities Service Guaranteed Loans: For the six-month period ended June 30, 2023, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $38,401,000 for long-term financing of general and environmental improvements at existing plants. In July 2023, we received an additional $19,900,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Pollution Control Revenue Bonds: On February 1, 2023, we remarketed $99,785,000 of Series 2017 pollution control revenue bonds. The remarketed bonds bear interest at an indexed rate until February 1, 2028 and are scheduled to mature in 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. |
Vogtle Units No. 3 and No. 4 Co
Vogtle Units No. 3 and No. 4 Construction Project | 6 Months Ended |
Jun. 30, 2023 | |
Vogtle Units No. 3 and No. 4 Construction Project | |
Vogtle Units No. 3 and No. 4 Construction Project | Vogtle Units No. 3 and No. 4 Construction Project. We, Georgia Power, the Municipal Electric Authority of Georgia (MEAG), and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services. In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement) and is reimbursed for actual costs plus a base fee and an at-risk fee, subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Cost and Schedule Our current budget for our ownership interest in Vogtle Units No. 3 and No. 4, which includes capital costs and allowance for funds used during construction, is $8.115 billion and is based on commercial operation dates of July 2023 and March 2024 for Units No. 3 and No. 4, respectively. This budget reflects our June 17, 2022 exercise of the tender option in the Global Amendments to the Joint Ownership Agreements as described below. Had we not exercised the tender option, our budget would be approximately $8.67 billion. At June 30, 2023, our total capital and financing costs for our interest in the additional Vogtle units was $8.4 billion, approximately $300 million of which relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power, as described below. The table below shows our project budget and actual costs through June 30, 2023 for our share of the project. (in millions) Project Budget Actual Costs at Construction Costs (1) $ 6,559 $ 6,393 Freeze Capital Credit (2) (532) — Financing Costs 2,038 1,925 Subtotal $ 8,065 $ 8,318 (3) Deferred Training Costs 47 47 Total Project Costs Before Contingency $ 8,112 $ 8,365 Oglethorpe Contingency $ 3 $ — Totals $ 8,115 $ 8,365 (1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements. (2) As described below, we exercised the tender option to cap our capital costs at the EAC in VCM 19 plus $2.1 billion, the freeze tender threshold. The freeze capital credit reflects our share of budgeted amounts that exceed this threshold. (3) At June 30, 2023, approximately $300 million relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power. Any schedule extension beyond March 2024 for Unit No. 4 is expected to increase our financing costs by approximately $10-$15 million per month for Unit No. 4. We and some of our members have implemented various rate management programs to lessen the impact on rates related to the additional Vogtle units. Our initial ownership interest and proportionate share of the cost to construct the additional Vogtle units was 30%, representing approximately 660 megawatts. However, we have exercised the tender option discussed below which caps our capital costs in exchange for a proportionate reduction of our 30% interest in the two units. Based on the current project budget and schedule and our interpretation of the Global Amendments (described below), we would transfer approximately 55 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share would decline from 30% to approximately 27.5%. However, if the total project costs exceed the current budget, our ownership share and megawatts would be further reduced. On March 6, 2023, the Unit No. 3 nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality, and, on April 1, 2023, the generator successfully synchronized to the power grid and generated electricity for the first time. Georgia Power placed Unit No. 3 in service on July 31, 2023. 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, engineering support, commodity installations, system turnovers and workforce statistics. Since March 2020, the number of active cases of COVID-19 at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion. As of June 30, 2023, the incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity, substantially all of which occurred during 2020 and 2021, is estimated by Georgia Power to be approximately $440 million, or approximately $130 million based on our initial 30% share, and is included in the project budget. On May 1, 2023, hot functional testing was completed at 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 allows nuclear fuel to be loaded and start-up testing to begin. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 during late fourth quarter 2023 or during the first quarter 2024. Given the remaining work to be done and potential risks associated with completing the work, our current budget anticipates an in-service date for Unit No. 4 in March 2024. Meeting the projected in-service date for Unit No. 4 significantly depends on maintaining overall construction productivity and production levels, particularly in completing remaining subcontractor scopes of work while reducing the level of craft laborers based on work remaining. As Unit No. 4 completes construction and transitions further into testing, ongoing and potential future challenges include the pace and quality of remaining commodities installations; the management of contractors and vendors, subcontractor performance, the availability of materials and parts, and/or related cost escalation; the pace of remaining work package closures; and the availability of craft, supervisory and technical support resources; and the timeframe and duration of final component and 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 few years began initial operation in the global nuclear industry at this scale). These challenges may result in further schedule delays and/or cost increases. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to ensure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. With the receipt of the Nuclear Regulatory Commission’s 103(g) 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 to the Co-owners. The ultimate outcome of these matters cannot be determined at this time. Co-Owner Contracts and Other Information In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. These joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further on September 26, 2018 by the Term Sheet that was memorialized on February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) to the Joint Ownership Agreements (as amended, the Joint Ownership Agreements). As a result of an increase in the total project capital cost forecast and Georgia Power’s decision not to seek recovery of its allocation of the increase in the base capital costs and the increased construction budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring report (VCM 19) in 2018, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners unanimously voted to continue construction of Vogtle Units No. 3 and No. 4. In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC to mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that: • each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's VCM 19 filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs; • Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and • Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest). If the EAC is revised and exceeds the EAC in VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, has a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s share of construction costs actually incurred in excess of the EAC in VCM 19 plus $2.1 billion. If any Co-owner elects to exercise this tender option, Georgia Power would have the option to cancel the project in lieu of accepting the offer to purchase a portion of the Co-owner’s ownership interest. If Georgia Power does not elect to cancel the project, then Georgia Power must accept the offer, and the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the percentage of the cumulative amount of construction costs paid by such tendering Co-owner as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of the tendering Co-owner in accordance with the second and third bullets above will be treated as payments made by that Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase allowed us to freeze our construction budget associated with the Vogtle project in exchange for a proportionate reduction of our 30% ownership interest. The VCM 19 total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. As of December 31, 2021, budget increases since VCM 19 reached $3.4 billion for all Co-owners. As a result of those increases, we believe that the tender option was triggered at the Co-owner construction budget vote on February 14, 2022 and that Georgia Power’s increased responsibility for certain construction costs as described above commenced in March 2022. On June 17, 2022, we notified Georgia Power of our election to exercise the tender option and cap our capital costs in exchange for a proportionate reduction of our 30% interest in the two new units. Our decremental ownership interest will be calculated and conveyed to Georgia Power after both Vogtle units are placed in service. Based on the current project budget, our schedule assumptions and our interpretation of the Global Amendments, our project budget is $8.1 billion and we expect to transfer approximat ely 55 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately 27.5%. By exercising the tender option and based on current assumptions, we estimate that we will avoid incurring approxim ately $535 million in c onstruction costs associated with the project. However, if the total project costs exceed the current budget, our ownership share and megawatts would be further reduced. On July 26, 2022, the City of Dalton notified Georgia Power that it had elected to exercise its tender option. We and Georgia Power do not agree on certain aspects of the tender option, including the dollar amount that triggers our option to tender a portion of our ownership interest to Georgia Power under the tender option or the extent to which costs that are the result of a force majeure event (such as COVID-19) impact the point at which the tender option is triggered. For purposes of determining when our option to tender was triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. We and Georgia Power also do not agree on the dollar amount that triggered Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above was triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in VCM 19 by $800 million to $2.1 billion. Accordingly, in March 2022, we notified Georgia Power of a billing dispute with regards to both the starting dollar amount and the application of costs resulting from a force majeure event and how such amounts impact the thresholds and timing of the cost-sharing and tender option provisions. On June 18, 2022, after completing the dispute resolution procedures set forth in the Ownership Participation Agreement for the additional Vogtle units, we and MEAG filed separate lawsuits against Georgia Power in the Superior Court of Fulton County, Georgia seeking to enforce the terms of the Global Amendments. Our lawsuit seeks declaratory judgment that the cost sharing and tender provisions of the Global Amendments have been triggered based on a VCM 19 forecast of $17.1 billion . Our lawsuit also alleges breach of contract and asserts other claims and seeks damages and injunctive relief requiring Georgia Power to track and allocate construction costs consistent with our interpretation of the Global Amendments. On July 28, 2022, Georgia Power filed a counterclaim against us seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power’s related financial obligations. Based on the current project budget and Georgia Power’s interpretation of the Global Amendments, our project budget would be $8.67 billion, and we would incur approxima tely $535 million of additional construction costs (excluding related financing costs) and retain substantially all of our 30% interest in the additional units. On September 26, 2022, the City of Dalton filed a complaint in our lawsuit and joined our claims. On September 29, 2022, Georgia Power and MEAG reached an agreement with respect to their pending litigation. Pursuant to the Joint Ownership Agreements, as amended by the Global Amendments, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Global Amendment provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Georgia Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more from the seventeenth VCM report estimated in-service dates of November 2021 and November 2022 for Units No. 3 and No. 4, respectively (each, a Project Adverse Event). The schedule extensions, announced in February 2022, which reflected a cumulative delay of over a year for each unit from the schedules approved in the seventeenth VCM report, triggered the requirement for the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 to vote to continue construction, and the Co-owners unanimously voted to continue construction. The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note L of Notes to Unaudited Consolidated Financial Statements. The ultimate outcome of these matters cannot be determined at this time. |
Measurement of Credit Losses on
Measurement of Credit Losses on Financial Instruments | 6 Months Ended |
Jun. 30, 2023 | |
Accounting Policies [Abstract] | |
Measurement of Credit Losses on Financial Instruments | Measurement of Credit Losses on Financial Instruments. The financial assets we hold that are subject to credit losses (Topic 326) are predominately accounts receivable and certain cash equivalents classified as held-to-maturity debt (e.g. commercial paper). Our receivables are generally due within thirty days or less with a significant portion related to billings to our members. See Note F for information regarding our member receivables. Commercial paper issuances we invest in are rated as investment grade and backed by a credit facility. Given our historical experience, the short duration lifetime of these financial assets and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of these financial assets is remote and we have not recognized an allowance for credit losses. |
Plant Wansley
Plant Wansley | 6 Months Ended |
Jun. 30, 2023 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Plant Wansley | Plant Wansley. In July 2022, the Georgia Public Service Commission approved Georgia Power’s 2022 integrated resource plan. This plan requested the decertification of coal-fired Plant Wansley, of which we own a 30% interest, by August 31, 2022. In accordance with the approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of the remaining plant in service assets associated with Plant Wansley based upon the August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will be recovered through future rates over a period ending no later than December 31, 2040. The Georgia Public Service Commission also approved Georgia Power’s modified closure proposal for the ash pond at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Asset Retirement Obligations. On March 6, 2023, Plant Vogtle Unit No. 3's nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality. During the first quarter of 2023, we recognized new nuclear asset retirement obligations totaling $62.8 million. During the first quarter of 2023, we also recorded an increase in cash flow estimates of $24.7 million related to existing coal ash related asset retirement obligations. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures. |
Asset Retirement Obligations
Asset Retirement Obligations | 6 Months Ended |
Jun. 30, 2023 | |
Asset Retirement Obligation [Abstract] | |
Asset Retirement Obligations | Plant Wansley. In July 2022, the Georgia Public Service Commission approved Georgia Power’s 2022 integrated resource plan. This plan requested the decertification of coal-fired Plant Wansley, of which we own a 30% interest, by August 31, 2022. In accordance with the approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of the remaining plant in service assets associated with Plant Wansley based upon the August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will be recovered through future rates over a period ending no later than December 31, 2040. The Georgia Public Service Commission also approved Georgia Power’s modified closure proposal for the ash pond at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Asset Retirement Obligations. On March 6, 2023, Plant Vogtle Unit No. 3's nuclear reactor achieved self-sustaining nuclear fission, commonly referred to as initial criticality. During the first quarter of 2023, we recognized new nuclear asset retirement obligations totaling $62.8 million. During the first quarter of 2023, we also recorded an increase in cash flow estimates of $24.7 million related to existing coal ash related asset retirement obligations. We expect to periodically receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures. |
Plant Acquisition
Plant Acquisition | 6 Months Ended |
Jun. 30, 2023 | |
Business Combination and Asset Acquisition [Abstract] | |
Plant Acquisition | Plant Acquisition. 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. The unit also features dual-fuel capability and can run on diesel fuel that is stored on site with an aggregate summer planning reserve generation capacity of 47 megawatts. 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. We submitted a loan application to the Rural Utilities Service for long-term financing of this acquisition. For any amounts not funded through the Rural Utilities Service, we intend to issue first mortgage bonds. We expect that any financing from the Rural Utilities Service or through first mortgage bonds will be secured under our first mortgage indenture. The following amounts represent the identifiable assets acquired and liabilities assumed in the 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. |
Insider Trading Arrangements
Insider Trading Arrangements | 3 Months Ended |
Jun. 30, 2023 | |
Trading Arrangements, by Individual | |
Rule 10b5-1 Arrangement Adopted | false |
Non-Rule 10b5-1 Arrangement Adopted | false |
Rule 10b5-1 Arrangement Terminated | false |
Non-Rule 10b5-1 Arrangement Terminated | false |
Recently Issued or Adopted Ac_2
Recently Issued or Adopted Accounting Pronouncements (Policies) | 6 Months Ended |
Jun. 30, 2023 | |
Accounting Standards Update and Change in Accounting Principle [Abstract] | |
Recently Issued or Adopted Accounting Pronouncements | Recently Issued or Adopted Accounting Pronouncements. As of June 30, 2023, we have implemented all applicable new accounting standards and updates issued by the Financial Accounting Standards Board (FASB) that were in effect. There were no applicable standards or updates during the six months ended June 30, 2023 that had a material impact on our consolidated financial statements. |
General (Tables)
General (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |
Schedule of Balances After Correction of Misstatement | After correction of this misstatement the balances presented for the quarter ended March 31, 2023 were as follows: (dollars in thousands) Depreciation and amortization, including nuclear fuel $ 92,645 Net cash used in operating activities (64,810) Property additions (285,233) Net cash used in investing activities (200,535) |
Fair Value (Tables)
Fair Value (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Fair Value Disclosures [Abstract] | |
Schedule of assets and liabilities measured at fair value on a recurring basis | The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2023 and December 31, 2022. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs June 30, 2023 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 217,632 $ 217,632 $ — $ — International equity trust 128,828 — 128,828 — Corporate bonds and debt 67,669 — 67,614 55 US Treasury securities 54,112 54,112 — — Mortgage backed securities 39,314 — 39,314 — Domestic mutual funds 73,435 73,435 — — Federal agency securities 7,565 — 7,565 — International mutual funds 717 — 717 — Non-US Gov't bonds & private placements 2,730 — 2,730 — Other 6,355 6,054 301 — Long-term investments: International equity trust 38,629 — 38,629 — Corporate bonds and debt 12,273 — 12,273 — US Treasury securities 16,803 16,803 — — Mortgage backed securities 13,495 — 13,495 — Domestic mutual funds 334,003 334,003 — — Treasury STRIPS 240,747 — 240,747 — Non-US Gov't bonds & private placements 1,751 — 1,751 — Other 78 78 — — Short-term investments: Treasury STRIPS 90,147 — 90,147 — Natural gas swaps 49,235 — 49,235 — Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2022 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 204,129 $ 204,129 $ — $ — International equity trust 111,266 — 111,266 — Corporate bonds and debt 60,806 — 60,788 18 US Treasury securities 49,775 49,775 — — Mortgage backed securities 41,210 — 41,210 — Domestic mutual funds 57,348 57,348 — — Federal agency securities 2,037 — 2,037 — Non-US Gov't bonds & private placements 2,890 — 2,890 — International mutual funds 653 — 653 — Other 10,602 10,602 — — Long-term investments: International equity trust 33,606 — 33,606 — Corporate bonds and debt 10,473 — 10,473 — US Treasury securities 15,488 15,488 — — Mortgage backed securities 12,113 — 12,113 — Domestic mutual funds 302,302 302,302 — — Treasury STRIPS 293,281 — 293,281 — Non-US Gov't bonds & private placements 1,976 — 1,976 — Other 240 240 — — Short-term investments: Treasury STRIPS 61,702 — 61,702 — Natural gas swaps 131,804 — 131,804 — |
Schedule of estimated fair values of long-term debt, including current maturities | The estimated fair values of our long-term debt, including current maturities at June 30, 2023 and December 31, 2022 were as follows: 2023 2022 Carrying Fair Carrying Fair (in thousands) Long-term debt $ 11,768,875 $ 10,214,166 $ 11,940,359 $ 10,194,954 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | |
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year | The following table reflects the notional volume of our natural gas derivatives as of June 30, 2023 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2023 19.8 2024 30.5 2025 25.0 2026 20.3 2027 7.7 Total 103.3 |
Schedule of fair value of derivative instruments and effect on consolidated balance sheets | The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2023 and December 31, 2022. Balance Sheet Location Fair Value 2023 2022 (dollars in thousands) Assets: Natural gas swaps Other current assets $ 9,688 $ 35,285 Natural gas swaps Other deferred charges $ 44,681 $ 99,725 Liabilities: Natural gas swaps Other current liabilities $ 5,115 $ 3,206 Natural gas swaps Other deferred credits $ 19 $ — |
Schedule of the realized gains and (losses) on derivative instruments recognized in margin | The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and six months ended June 30, 2023 and 2022. Statement of Three Months Ended June 30, Six Months Ended 2023 2022 2023 2022 (dollars in thousands) Natural gas swaps gains Fuel $ 5 $ 42,563 $ 140 $ 50,641 Natural gas swaps losses Fuel (7,207) (203) (16,604) (282) Total $ (7,202) $ 42,360 $ (16,464) $ 50,359 |
Schedule of unrealized gains on derivative instruments deferred on the balance sheet | The following table presents the unrealized gains on derivative instruments deferred on the balance sheet at June 30, 2023 and December 31, 2022. Balance Sheet Location 2023 2022 (dollars in thousands) Natural gas swaps Regulatory liability $ 49,235 $ 131,804 Total $ 49,235 $ 131,804 |
Investment Securities (Tables)
Investment Securities (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Investments, Debt and Equity Securities [Abstract] | |
Summary of debt and equity securities | The following tables summarize debt and equity securities as of June 30, 2023 and December 31, 2022. Gross Unrealized (dollars in thousands) June 30, 2023 Cost Gains Losses Fair Equity $ 330,886 $ 209,975 $ (6,023) $ 534,838 Debt 843,576 1,057 (39,246) 805,387 Other 6,006 59 (7) 6,058 Total $ 1,180,468 $ 211,091 $ (45,276) $ 1,346,283 Gross Unrealized (dollars in thousands) December 31, 2022 Cost Gains Losses Fair Equity $ 323,907 $ 159,445 $ (8,949) $ 474,403 Debt 833,035 372 (46,369) 787,038 Other 10,445 20 (9) 10,456 Total $ 1,167,387 $ 159,837 $ (55,327) $ 1,271,897 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Schedule of sales to members and sales to non-members | Sales to members for the three and six months ended June 30, 2023 and 2022 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2023 2022 2023 2022 Capacity revenues $ 234,183 $ 241,841 $ 476,227 $ 485,132 Energy revenues 131,313 236,941 276,922 411,099 Total $ 365,496 $ 478,782 $ 753,149 $ 896,231 Member energy requirements supplied 71 % 59 % 68 % 58 % Three Months Ended Six Months Ended (dollars in thousands) 2023 2022 2023 2022 Energy revenues $ 20,269 $ 54,346 $ 21,306 $ 57,339 Capacity revenues 3,624 — 4,387 — Total $ 23,893 $ 54,346 $ 25,693 $ 57,339 |
Leases (Tables)
Leases (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Leases [Abstract] | |
Schedule of balance sheet impact of leases | For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (275,512) (272,876) Total finance lease assets $ 27,220 $ 29,856 Lease liabilities—Finance leases Obligations under finance leases $ 48,388 $ 52,937 Long-term debt and finance leases due within one year 8,861 8,398 Total finance lease liabilities $ 57,249 $ 61,335 Classification June 30, 2023 December 31, 2022 (dollars in thousands) Right-of-use assets—Operating leases Electric plant in service, net $ 2,734 $ 3,326 Total operating lease assets $ 2,734 $ 3,326 Lease liabilities—Operating leases Capitalization—Other $ 1,825 $ 2,256 Other current liabilities 1,003 1,164 Total operating lease liabilities $ 2,828 $ 3,420 |
Schedule of lease cost | Three months ended Six months ended Lease Cost Classification June 30, 2023 June 30, 2022 June 30, 2023 June 30, 2022 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 2,100 $ 1,886 $ 4,199 $ 3,771 Interest on lease liabilities Interest expense 1,638 1,852 3,276 3,704 Operating lease cost: Inventory (1) & production expense 328 222 657 444 Total leased cost $ 4,066 $ 3,960 $ 8,132 $ 7,919 (1) The majority of our operating lease costs relate to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. |
Summary of lease terms and discount rates | June 30, 2023 December 31, 2022 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 5.72 5.94 Operating leases 6.87 6.44 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 5.63 % 5.52 % |
Schedule of cash paid for amounts included in the measurement of lease liabilities | Six months ended June 30, 2023 2022 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 3,389 $ 3,806 Operating cash flows from operating leases $ 657 $ 444 Financing cash flows from finance leases $ 4,086 $ 3,669 Right-of-use assets obtained in exchange for new operating lease liabilities $ — $ — |
Schedule of maturities of finance lease liabilities | Maturity analysis of our finance and operating lease liabilities as of June 30, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 7,475 $ 667 $ 8,142 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,685 868 11,553 Total lease payments $ 77,956 $ 3,448 $ 81,404 Less: imputed interest (20,707) (620) (21,327) Present value of lease liabilities $ 57,249 $ 2,828 $ 60,077 |
Schedule of maturities of operating lease liabilities | Maturity analysis of our finance and operating lease liabilities as of June 30, 2023 is as follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2023 $ 7,475 $ 667 $ 8,142 2024 14,949 850 15,799 2025 14,949 641 15,590 2026 14,949 350 15,299 2027 14,949 72 15,021 Thereafter 10,685 868 11,553 Total lease payments $ 77,956 $ 3,448 $ 81,404 Less: imputed interest (20,707) (620) (21,327) Present value of lease liabilities $ 57,249 $ 2,828 $ 60,077 |
Schedule of lease income | Lease income recognized during the three and six months ended June 30, 2023 and 2022 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2023 2022 2023 2022 (dollars in thousands) Lease income $ 1,691 $ 1,669 $ 3,376 $ 3,314 |
Restricted Cash and Investmen_2
Restricted Cash and Investments (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Restricted Investments Note [Abstract] | |
Reconciliation of cash, cash equivalents and restricted cash | The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the unaudited consolidated balance sheets that sum to the total of the same such amounts reported in the unaudited consolidated statements of cash flows. Classification Six months ended June 30, 2023 June 30, 2022 (dollars in thousands) Cash and cash equivalents $ 459,368 $ 476,792 Bond purchase fund — 30,975 Restricted cash included in restricted cash and short-term investments 5,600 84,600 Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows $ 464,968 $ 592,367 |
Regulatory Assets and Liabili_2
Regulatory Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Regulatory Assets and Liabilities Disclosure [Abstract] | |
Schedule of regulatory assets and liabilities | The following regulatory assets and liabilities are reflected on the consolidated balance sheets as of June 30, 2023 and December 31, 2022. 2023 2022 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 27,485 $ 29,494 Amortization of financing leases(b) 30,344 31,908 Outage costs(c) 36,043 29,317 Asset retirement obligations—Ashpond and other(l) 376,122 353,212 Asset retirement obligations—Nuclear(l) — 32,192 Depreciation expense - Plant Vogtle(d) 34,838 35,549 Depreciation expense - Plant Wansley(e) 351,734 361,784 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) 55,669 54,701 Interest rate options cost(g) 139,539 136,827 Deferral of effects on net margin—Smith Energy Facility(h) 133,758 136,730 Other regulatory assets(o) 13,287 10,591 Total Regulatory Assets $ 1,198,819 $ 1,212,305 Regulatory Liabilities: Accumulated retirement costs for other obligations(i) $ 34,296 $ 35,580 Deferral of effects on net margin—Hawk Road Energy Facility(h) 16,328 16,636 Deferral of effects on net margin—Bobby C. Smith Jr. Energy Facility(p) 6,941 14,825 Major maintenance reserve(j) 94,395 74,584 Amortization of financing leases(b) 4,108 5,557 Deferred debt service adder(k) 162,516 154,514 Asset retirement obligations—Nuclear(l) 19,520 — Revenue deferral plan(m) 330,949 357,460 Natural gas hedges(n) 49,235 131,804 Other regulatory liabilities(o) 1,076 1,230 Total Regulatory Liabilities $ 719,364 $ 792,190 Net Regulatory Assets $ 479,455 $ 420,115 (a) Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 21 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Represents the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which occurred on August 31, 2022. Amortization commenced upon the retirement of Plant Wansley and will end no later than December 31, 2040. (f) Deferred charges consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (g) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No. 3 and No. 4. Amortization commenced in August 2023 after Vogtle Unit No. 3 was placed in service on July 31, 2023. (h) Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant. (i) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (j) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (k) Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants. (l) Represents the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (m) Deferred revenues under a rate management program that allowed for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings, per each members' election, over the subsequent five-year period. (n) Represents the deferral of unrealized gains on natural gas contracts. (o) The amortization periods for other regulatory assets range up to 27 years and the amortization periods of other regulatory liabilities range up to 4 years. (p) Effects on net margin for the Bobby C. Smith Jr. Energy Facility that are being deferred until on or before January 2026 and will be amortized over the remaining life of the plant. |
Vogtle Units No. 3 and No. 4 _2
Vogtle Units No. 3 and No. 4 Construction Project (Tables) | 6 Months Ended |
Jun. 30, 2023 | |
Vogtle Units No. 3 and No. 4 Construction Project | |
Schedule of Project Budget and Actual Costs | The table below shows our project budget and actual costs through June 30, 2023 for our share of the project. (in millions) Project Budget Actual Costs at Construction Costs (1) $ 6,559 $ 6,393 Freeze Capital Credit (2) (532) — Financing Costs 2,038 1,925 Subtotal $ 8,065 $ 8,318 (3) Deferred Training Costs 47 47 Total Project Costs Before Contingency $ 8,112 $ 8,365 Oglethorpe Contingency $ 3 $ — Totals $ 8,115 $ 8,365 (1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements. (2) As described below, we exercised the tender option to cap our capital costs at the EAC in VCM 19 plus $2.1 billion, the freeze tender threshold. The freeze capital credit reflects our share of budgeted amounts that exceed this threshold. (3) At June 30, 2023, approximately $300 million relates to costs that exceed the tender option threshold that is the subject of litigation between us and Georgia Power. |
Plant Acquisition (Tables)
Plant Acquisition (Tables) | 6 Months Ended |
Jun. 30, 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 |
General (Details)
General (Details) $ in Thousands | 3 Months Ended | 6 Months Ended | |
Mar. 31, 2023 USD ($) | Jun. 30, 2023 USD ($) member | Jun. 30, 2022 USD ($) | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Number of electric distribution cooperative members | member | 38 | ||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Depreciation and amortization, including nuclear fuel | $ 92,645 | $ 196,729 | $ 203,299 |
Property additions | 285,233 | $ 495,134 | $ 526,406 |
Adjustment | |||
Error Corrections and Prior Period Adjustments Restatement [Line Items] | |||
Depreciation and amortization, including nuclear fuel | 26,100 | ||
Property additions | $ 26,100 |
General - Balances After Correc
General - Balances After Correction of Misstatement (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |
Mar. 31, 2023 | Jun. 30, 2023 | Jun. 30, 2022 | |
Organization, Consolidation and Presentation of Financial Statements [Abstract] | |||
Depreciation and amortization, including nuclear fuel | $ 92,645 | $ 196,729 | $ 203,299 |
Net cash used in operating activities | (64,810) | 166 | 169,547 |
Property additions | (285,233) | (495,134) | (526,406) |
Net cash used in investing activities | $ (200,535) | $ (419,026) | $ (373,890) |
Fair Value - Asset and liabilit
Fair Value - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($) | 6 Months Ended | |
Jun. 30, 2023 | Dec. 31, 2022 | |
Fair value | ||
Nuclear decommissioning trust fund | $ 598,357,000 | $ 540,716,000 |
Long-term investments | 657,779,000 | 669,479,000 |
Short-term investments | 90,147,000 | 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 | $ 49,235,000 | 131,804,000 |
Recurring basis | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 217,632,000 | 204,129,000 |
Recurring basis | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 128,828,000 | 111,266,000 |
Long-term investments | 38,629,000 | 33,606,000 |
Recurring basis | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 67,669,000 | 60,806,000 |
Long-term investments | 12,273,000 | 10,473,000 |
Recurring basis | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 54,112,000 | 49,775,000 |
Long-term investments | 16,803,000 | 15,488,000 |
Recurring basis | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 39,314,000 | 41,210,000 |
Long-term investments | 13,495,000 | 12,113,000 |
Recurring basis | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 73,435,000 | 57,348,000 |
Long-term investments | 334,003,000 | 302,302,000 |
Recurring basis | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 7,565,000 | 2,037,000 |
Recurring basis | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 240,747,000 | 293,281,000 |
Short-term investments | 90,147,000 | 61,702,000 |
Recurring basis | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 717,000 | 653,000 |
Recurring basis | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,730,000 | 2,890,000 |
Long-term investments | 1,751,000 | 1,976,000 |
Recurring basis | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 6,355,000 | 10,602,000 |
Long-term investments | 78,000 | 240,000 |
Recurring basis | (Level 1) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 0 | 0 |
Recurring basis | (Level 1) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 217,632,000 | 204,129,000 |
Recurring basis | (Level 1) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 1) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 1) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 54,112,000 | 49,775,000 |
Long-term investments | 16,803,000 | 15,488,000 |
Recurring basis | (Level 1) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 1) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 73,435,000 | 57,348,000 |
Long-term investments | 334,003,000 | 302,302,000 |
Recurring basis | (Level 1) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | (Level 1) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 0 | 0 |
Short-term investments | 0 | 0 |
Recurring basis | (Level 1) | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | (Level 1) | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 1) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 6,054,000 | 10,602,000 |
Long-term investments | 78,000 | 240,000 |
Recurring basis | (Level 2) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 49,235,000 | 131,804,000 |
Recurring basis | (Level 2) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | (Level 2) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 128,828,000 | 111,266,000 |
Long-term investments | 38,629,000 | 33,606,000 |
Recurring basis | (Level 2) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 67,614,000 | 60,788,000 |
Long-term investments | 12,273,000 | 10,473,000 |
Recurring basis | (Level 2) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 2) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 39,314,000 | 41,210,000 |
Long-term investments | 13,495,000 | 12,113,000 |
Recurring basis | (Level 2) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 2) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 7,565,000 | 2,037,000 |
Recurring basis | (Level 2) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 240,747,000 | 293,281,000 |
Short-term investments | 90,147,000 | 61,702,000 |
Recurring basis | (Level 2) | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 717,000 | 653,000 |
Recurring basis | (Level 2) | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 2,730,000 | 2,890,000 |
Long-term investments | 1,751,000 | 1,976,000 |
Recurring basis | (Level 2) | Other | ||
Fair value | ||
Nuclear decommissioning trust fund | 301,000 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | Natural gas swaps | ||
Fair value | ||
Derivative liabilities | 0 | 0 |
Recurring basis | (Level 3) | Domestic equity | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | (Level 3) | International equity trust | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | Corporate bonds and debt | ||
Fair value | ||
Nuclear decommissioning trust fund | 55,000 | 18,000 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | US Treasury securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | Mortgage backed securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | Domestic mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | Federal agency securities | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | (Level 3) | Treasury STRIPS | ||
Fair value | ||
Long-term investments | 0 | 0 |
Short-term investments | 0 | 0 |
Recurring basis | (Level 3) | International mutual funds | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Recurring basis | (Level 3) | Non-US Gov't bonds & private placements | ||
Fair value | ||
Nuclear decommissioning trust fund | 0 | 0 |
Long-term investments | 0 | 0 |
Recurring basis | (Level 3) | 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 | Jun. 30, 2023 | Dec. 31, 2022 |
Carrying Value | ||
Fair Value | ||
Long-term debt | $ 11,768,875 | $ 11,940,359 |
Fair Value | (Level 2) | ||
Fair Value | ||
Long-term debt | $ 10,214,166 | $ 10,194,954 |
Derivative Instruments - Natura
Derivative Instruments - Natural gas derivatives (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions | 6 Months Ended | |
Jun. 30, 2023 USD ($) MMBTU | Dec. 31, 2022 USD ($) | |
Derivative Instruments | ||
Derivative asset | $ | $ 49,235 | $ 131,804 |
Notional volume of natural gas derivatives (in MMBTUs) | 103.3 | |
One counterparty | ||
Derivative Instruments | ||
Credit collateral posted | $ | $ 5,600 | $ 30,400 |
2023 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 19.8 | |
2024 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 30.5 | |
2025 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 25 | |
2026 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 20.3 | |
2027 | ||
Derivative Instruments | ||
Notional volume of natural gas derivatives (in MMBTUs) | 7.7 |
Derivative Instruments - Fair v
Derivative Instruments - Fair value of derivative instruments (Details) - Natural gas swaps - USD ($) $ in Thousands | Jun. 30, 2023 | Dec. 31, 2022 |
Assets: | ||
Fair value of assets | $ 49,235 | $ 131,804 |
Other current assets | ||
Assets: | ||
Fair value of assets | 9,688 | 35,285 |
Other deferred charges | ||
Assets: | ||
Fair value of assets | 44,681 | 99,725 |
Other current liabilities | ||
Liabilities: | ||
Fair value of liabilities | 5,115 | 3,206 |
Other deferred credits | ||
Liabilities: | ||
Fair value of liabilities | $ 19 | $ 0 |
Derivative Instruments - Realiz
Derivative Instruments - Realized and unrealized gains (losses) on derivative instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Gains and (losses) on derivative instruments | |||||
Net unrealized gains on derivative instruments | $ 49,235 | $ 131,804 | |||
Natural gas swaps | |||||
Gains and (losses) on derivative instruments | |||||
Gains | $ 5 | $ 42,563 | 140 | $ 50,641 | |
Losses | (7,207) | (203) | (16,604) | (282) | |
Total | $ (7,202) | $ 42,360 | (16,464) | $ 50,359 | |
Natural gas swaps | Regulatory liability | |||||
Gains and (losses) on derivative instruments | |||||
Net unrealized gains on derivative instruments | $ 49,235 | $ 131,804 |
Investment Securities (Details)
Investment Securities (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended |
Jun. 30, 2023 | Dec. 31, 2022 | |
Cost | ||
Equity | $ 330,886 | $ 323,907 |
Debt | 843,576 | 833,035 |
Other | 6,006 | 10,445 |
Total | 1,180,468 | 1,167,387 |
Gains | ||
Equity | 209,975 | 159,445 |
Debt | 1,057 | 372 |
Other | 59 | 20 |
Total | 211,091 | 159,837 |
Losses | ||
Equity | (6,023) | (8,949) |
Debt | (39,246) | (46,369) |
Other | (7) | (9) |
Total | (45,276) | (55,327) |
Fair Value | ||
Equity | 534,838 | 474,403 |
Debt | 805,387 | 787,038 |
Other | 6,058 | 10,456 |
Total | $ 1,346,283 | $ 1,271,897 |
Revenue Recognition - Additiona
Revenue Recognition - Additional Information (Details) $ in Thousands | 1 Months Ended | 3 Months Ended | 6 Months Ended | ||
Dec. 31, 2022 USD ($) unit | Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Jun. 30, 2023 USD ($) member service | Jun. 30, 2022 USD ($) | |
Revenue Recognition | |||||
Number of electric distribution cooperative members | member | 38 | ||||
Number of services provided | service | 2 | ||||
Member energy requirements supplied | 71% | 59% | 68% | 58% | |
Margins for interest ratio | 1.10 | ||||
Targeted margins for interest ratio | 1.14 | ||||
Refund liability | $ 28,471 | $ 4,000 | $ 5,000 | $ 4,000 | $ 5,000 |
Operating revenues | 389,389 | 533,128 | 778,842 | 953,570 | |
Washington County Power | Natural Gas Processing Plant | |||||
Revenue Recognition | |||||
Number of generating units acquried | unit | 2 | ||||
Members | |||||
Revenue Recognition | |||||
Operating revenues | 365,496 | 478,782 | 753,149 | 896,231 | |
Receivables from contracts | $ 187,401 | 139,422 | 139,422 | ||
Non-Members | |||||
Revenue Recognition | |||||
Operating revenues | 23,893 | 54,346 | 25,693 | 57,339 | |
Capacity revenues | Members | |||||
Revenue Recognition | |||||
Operating revenues | 234,183 | 241,841 | 476,227 | 485,132 | |
Capacity revenues | Non-Members | |||||
Revenue Recognition | |||||
Operating revenues | 3,624 | 0 | 4,387 | 0 | |
Energy revenues | Members | |||||
Revenue Recognition | |||||
Operating revenues | 131,313 | 236,941 | 276,922 | 411,099 | |
Energy revenues | Non-Members | |||||
Revenue Recognition | |||||
Operating revenues | 20,269 | $ 54,346 | 21,306 | $ 57,339 | |
Sale of Bobby C. Smith Jr. Deferring Members' Output | Non-Members | |||||
Revenue Recognition | |||||
Receivables from contracts | 8,787 | 6,951 | 6,951 | ||
Transactions with Affiliated Companies and Investment Income | Non-Members | |||||
Revenue Recognition | |||||
Receivables from contracts | $ 13,834 | $ 32,793 | $ 32,793 |
Revenue Recognition - Managemen
Revenue Recognition - Management Program (Details) - USD ($) $ in Thousands | 6 Months Ended | 12 Months Ended | |
Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2018 | |
Vogtle Units No. 3 & No. 4 | |||
Operating revenues | |||
Amounts billed under rate management program | $ 4,050 | $ 9,440 | |
Cumulative recovery of financing costs | 130,482 | ||
Vogtle New Units | |||
Operating revenues | |||
Cumulative recovery of financing costs | 337,675 | ||
Rate management program, additional collection period | 5 years | ||
Rate management program, billing period | 5 years | ||
Amounts billed under additional rate management program | $ 31,427 | $ 5,887 |
Leases - Summary (Details)
Leases - Summary (Details) | 6 Months Ended |
Jun. 30, 2023 lease option | |
Minimum | |
Leases | |
Finance lease renewal term | 1 year |
Maximum | |
Leases | |
Finance lease renewal term | 5 years |
Lease terms through December 31, 2027 | |
Leases | |
Number of finance leases | 3 |
Lease terms through June 30, 2031 | |
Leases | |
Number of finance leases | 1 |
Lease terms through February 2042 | |
Leases | |
Number of renewal options | option | 1 |
Operating lease, renewal term | 20 years |
Scherer Unit No. 2 | |
Leases | |
Percentage of undivided interest in Scherer Unit No. 2 | 60% |
Number of finance leases | 4 |
Leases - Balance Sheet Impact (
Leases - Balance Sheet Impact (Details) - USD ($) $ in Thousands | Jun. 30, 2023 | Dec. 31, 2022 |
Right-of-use assets—Finance leases | ||
Right-of-use assets | $ 302,732 | $ 302,732 |
Less: Accumulated provision for depreciation | (275,512) | (272,876) |
Total finance lease assets | $ 27,220 | $ 29,856 |
Finance lease, right-of-use asset, statement of financial position | Right-of-use assets—finance leases | Right-of-use assets—finance leases |
Lease liabilities—Finance leases | ||
Obligations under finance leases | $ 48,388 | $ 52,937 |
Long-term debt and finance leases due within one year | 8,861 | 8,398 |
Total finance lease liabilities | $ 57,249 | $ 61,335 |
Finance lease, liability, current, statement of financial position | Long-term debt and finance leases due within one year | Long-term debt and finance leases due within one year |
Right-of-use assets—Operating leases | ||
Electric plant in service, net | $ 2,734 | $ 3,326 |
Total operating lease assets | $ 2,734 | $ 3,326 |
Operating lease, right-of-use asset, statement of financial position | In service | In service |
Lease liabilities—Operating leases | ||
Capitalization—Other | $ 1,825 | $ 2,256 |
Other current liabilities | 1,003 | 1,164 |
Total operating lease liabilities | $ 2,828 | $ 3,420 |
Operating lease, liability, noncurrent, statement of financial position | Obligation under Hydro Facility Transactions | Obligation under Hydro Facility Transactions |
Operating lease, liability, current, statement of financial position | Other current liabilities | Other current liabilities |
Leases - Lease Cost (Details)
Leases - Lease Cost (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Lease Cost | |||||
Amortization of leased assets | $ 2,100 | $ 1,886 | $ 4,199 | $ 3,771 | |
Interest on lease liabilities | 1,638 | 1,852 | 3,276 | 3,704 | |
Operating lease cost: | 328 | 222 | 657 | 444 | |
Total leased cost | $ 4,066 | $ 3,960 | $ 8,132 | $ 7,919 | |
Weighted-average remaining lease term (in years) | |||||
Finance leases | 5 years 8 months 19 days | 5 years 8 months 19 days | 5 years 11 months 8 days | ||
Operating leases | 6 years 10 months 13 days | 6 years 10 months 13 days | 6 years 5 months 8 days | ||
Weighted-average discount rate: | |||||
Finance leases | 11.05% | 11.05% | 11.05% | ||
Operating leases | 5.63% | 5.63% | 5.52% |
Leases - Other Lease Disclosure
Leases - Other Lease Disclosures (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2023 | Jun. 30, 2022 | Jun. 30, 2023 | Jun. 30, 2022 | Dec. 31, 2022 | |
Lessee | |||||
Operating cash flows from finance leases | $ 3,389 | $ 3,806 | |||
Operating cash flows from operating leases | 657 | 444 | |||
Financing cash flows from finance leases | 4,086 | 3,669 | |||
Right-of-use assets obtained in exchange for new operating lease liabilities | 0 | 0 | |||
Finance Leases | |||||
2023 | $ 7,475 | 7,475 | |||
2024 | 14,949 | 14,949 | |||
2025 | 14,949 | 14,949 | |||
2026 | 14,949 | 14,949 | |||
2027 | 14,949 | 14,949 | |||
Thereafter | 10,685 | 10,685 | |||
Total lease payments | 77,956 | 77,956 | |||
Less: imputed interest | (20,707) | (20,707) | |||
Total finance lease liabilities | 57,249 | 57,249 | $ 61,335 | ||
Operating Leases | |||||
2023 | 667 | 667 | |||
2024 | 850 | 850 | |||
2025 | 641 | 641 | |||
2026 | 350 | 350 | |||
2027 | 72 | 72 | |||
Thereafter | 868 | 868 | |||
Total lease payments | 3,448 | 3,448 | |||
Less: imputed interest | (620) | (620) | |||
Total operating lease liabilities | 2,828 | 2,828 | $ 3,420 | ||
Total | |||||
2023 | 8,142 | 8,142 | |||
2024 | 15,799 | 15,799 | |||
2025 | 15,590 | 15,590 | |||
2026 | 15,299 | 15,299 | |||
2027 | 15,021 | 15,021 | |||
Thereafter | 11,553 | 11,553 | |||
Total lease payments | 81,404 | 81,404 | |||
Less: imputed interest | (21,327) | (21,327) | |||
Present value of lease liabilities | 60,077 | 60,077 | |||
Lessor | |||||
Lease income | $ 1,691 | $ 1,669 | $ 3,376 | $ 3,314 |
Contingencies and Regulatory _2
Contingencies and Regulatory Matters (Details) | 6 Months Ended |
Jun. 30, 2023 plaintiff | |
Contingencies and Regulatory Matters | |
Number of plaintiffs | 48 |
Restricted Cash and Investmen_3
Restricted Cash and Investments - Narrative (Details) - USD ($) | Jun. 30, 2023 | Dec. 31, 2022 |
Restricted Investments Note [Abstract] | ||
Restricted investments | $ 0 | $ 74,031,000 |
Restricted cash and short-term investments | $ 74,031,000 |
Restricted Cash and Investmen_4
Restricted Cash and Investments - Reconciliation of Cash, Cash Equivalents and Restricted Cash (Details) - USD ($) $ in Thousands | Jun. 30, 2023 | Dec. 31, 2022 | Jun. 30, 2022 | Dec. 31, 2021 |
Restricted Investments Note [Abstract] | ||||
Cash and cash equivalents | $ 459,368 | $ 595,381 | $ 476,792 | |
Bond purchase fund | 0 | 30,975 | ||
Restricted cash included in restricted cash and short-term investments | 5,600 | 84,600 | ||
Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows | $ 464,968 | $ 625,781 | $ 592,367 | $ 581,150 |
Regulatory Assets and Liabili_3
Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2023 | Dec. 31, 2022 | |
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 1,198,819 | $ 1,212,305 |
Total Regulatory Liabilities | 719,364 | 792,190 |
Net Regulatory Assets | 479,455 | 420,115 |
Accumulated retirement costs for other obligations | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 34,296 | 35,580 |
Deferral of effects on net margin - Hawk Road Energy Facility | Hawk Road Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 16,328 | 16,636 |
Deferral of effects on net margin - Hawk Road Energy Facility | Bobby C. Smith Jr. Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 6,941 | 14,825 |
Major maintenance reserve | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 94,395 | 74,584 |
Amortization of financing leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 4,108 | 5,557 |
Deferred debt service adder | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 162,516 | 154,514 |
Asset retirement obligations | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 19,520 | 0 |
Revenue deferral plan | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 330,949 | 357,460 |
Amortization period, regulatory liability | 5 years | |
Natural gas hedges | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 49,235 | 131,804 |
Other regulatory liabilities | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 1,076 | 1,230 |
Other regulatory liabilities | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, regulatory liability | 4 years | |
Premium and loss on reacquired debt | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 27,485 | 29,494 |
Premium and loss on reacquired debt | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 21 years | |
Amortization of financing leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 30,344 | 31,908 |
Outage costs | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 36,043 | 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 | $ 376,122 | 353,212 |
Asset retirement obligations | Nuclear | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 0 | 32,192 |
Depreciation expense | Plant Vogtle | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 34,838 | 35,549 |
Operating license expected extension period for Plant Vogtle | 20 years | |
Operating license period | 40 years | |
Depreciation expense | Plant Wansley | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 351,734 | 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 | 55,669 | 54,701 |
Interest rate options cost | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 139,539 | 136,827 |
Deferral of effects on net margin - Smith Energy Facility | Smith Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 133,758 | 136,730 |
Other regulatory assets | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 13,287 | $ 10,591 |
Other regulatory assets | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 27 years |
Debt - Department of Energy Loa
Debt - Department of Energy Loan Guarantee (Details) | 6 Months Ended | |||
Jun. 30, 2023 USD ($) | Jun. 30, 2022 USD ($) | Mar. 22, 2019 USD ($) | Feb. 20, 2014 USD ($) note | |
Debt | ||||
Repayments of long-term debt | $ 213,972,000 | $ 256,747,000 | ||
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 | $ 4,239,450,994 | |||
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 | $ 393,577,094 | |||
Long-term debt | FFB | Department of Energy guarantee | Services Agreement | ||||
Debt | ||||
Guarantee payment | $ 4,676,749,167 |
Debt - Rural Utilities Service
Debt - Rural Utilities Service Guaranteed Loans (Details) - Long-term debt - FFB - Rural Utilities Service Guaranteed Loans - USD ($) $ in Thousands | 1 Months Ended | 6 Months Ended |
Jul. 31, 2023 | Jun. 30, 2023 | |
Debt | ||
Advances received on loans | $ 38,401 | |
Subsequent Event | ||
Debt | ||
Advances received on loans | $ 19,900 |
Debt - Pollution Control Revenu
Debt - Pollution Control Revenue Bonds (Details) $ in Thousands | Feb. 01, 2023 USD ($) |
Municipal bonds | Series 2017 Pollution Control Revenue Bonds | |
Debt | |
Debt instrument, face amount | $ 99,785 |
Vogtle Units No. 3 and No. 4 _3
Vogtle Units No. 3 and No. 4 Construction Project - Narrative (Details) $ in Millions | 6 Months Ended | ||
Feb. 18, 2019 USD ($) | Jun. 30, 2023 USD ($) unit MW | Dec. 31, 2021 USD ($) | |
Loan Guarantee Agreement | |||
Public Utility Property Plant and Equipment | |||
Term of debt | 5 years | ||
Vogtle Units No. 3 & No. 4 | |||
Public Utility Property Plant and Equipment | |||
Total investment in additional Vogtle units | $ 8,400 | ||
Investment in excess of tender option | $ 300 | ||
Ownership interest (as a percent) | 30% | ||
COVID related costs | $ 440 | ||
Proportionate share of COVID related costs | $ 130 | ||
Remaining share paid by counterparty upon exercise of tender option (as a percent) | 100% | ||
Budget increases since the nineteenth VCM | $ 3,400 | ||
Percentage of disallowed costs excluded from adverse event triggers | 6% | ||
Vogtle Units No. 3 & No. 4 | Jointly Owned Nuclear Power Plant | |||
Public Utility Property Plant and Equipment | |||
Release of generating capacity with exercise of tender option (in megawatts) | MW | 55 | ||
Proportionate ownership share with exercise of tender option (as a percent) | 27.50% | ||
Total project cost | $ 8,115 | ||
Vogtle Units No. 3 & No. 4 | Financial Exposure Term One | |||
Public Utility Property Plant and Equipment | |||
Ownership interest (as a percent) | 30% | ||
Vogtle Units No. 3 & No. 4 | Financial Exposure Term Two | |||
Public Utility Property Plant and Equipment | |||
Ownership interest (as a percent) | 30% | ||
Vogtle Units No. 3 & No. 4 | EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||
Public Utility Property Plant and Equipment | |||
Number of nuclear units | unit | 2 | ||
Generating capacity of each nuclear unit (in megawatts) | MW | 1,100 | ||
Vogtle Units No. 3 & No. 4 | Services Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||
Public Utility Property Plant and Equipment | |||
Written notice period for termination of agreement | 30 days | ||
Vogtle Units No. 3 & No. 4 | Ownership participation agreement | |||
Public Utility Property Plant and Equipment | |||
Project budget | $ 8,115 | ||
Project budget had tender option not been exercised | $ 8,670 | ||
Ownership share, generating capacity (in megawatts) | MW | 660 | ||
Construction cost savings due to exercise of tender option | $ 535 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | |||
Public Utility Property Plant and Equipment | |||
Project budget | $ 8,400 | ||
Additional construction costs | $ 800 | ||
Total project cost | 17,100 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Jointly Owned Nuclear Power Plant | |||
Public Utility Property Plant and Equipment | |||
Total project cost | 17,100 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Jointly Owned Nuclear Power Plant | Georgia Power | |||
Public Utility Property Plant and Equipment | |||
Project budget | 8,670 | ||
Total project cost | 18,380 | ||
Increase in project budget based on Georgia Power's interpretation | $ 535 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term One | |||
Public Utility Property Plant and Equipment | |||
Proportionate share of construction costs, co-owner (as a percent) | 55.70% | ||
Additional construction costs, responsibility of co-owner | $ 80 | ||
Proportionate share of additional construction costs | $ 44 | ||
Proportionate share of construction costs, remaining co-owners (as a percent) | 44.30% | ||
Proportionate share of construction costs (as a percent) | 24.50% | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term Two | |||
Public Utility Property Plant and Equipment | |||
Proportionate share of construction costs, co-owner (as a percent) | 65.70% | ||
Additional construction costs, responsibility of co-owner | $ 100 | ||
Proportionate share of additional construction costs | $ 55 | ||
Proportionate share of construction costs, remaining co-owners (as a percent) | 34.30% | ||
Proportionate share of construction costs (as a percent) | 19% | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Financial Exposure Term Three | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs triggering option to tender ownership | $ 2,100 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | |||
Public Utility Property Plant and Equipment | |||
Ownership approval to change primary construction contractor (as a percent) | 90% | ||
Ownership approval required to continue construction (as a percent) | 90% | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term One | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs | 800 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term Two | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs | 1,600 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Minimum | Financial Exposure Term Three | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs triggering option to tender ownership | 800 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term One | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs | 1,600 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term Two | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs | 2,100 | ||
Vogtle Units No. 3 & No. 4 | Global Amendments To Term Sheet | Maximum | Financial Exposure Term Three | |||
Public Utility Property Plant and Equipment | |||
Additional construction costs triggering option to tender ownership | $ 2,100 | ||
Vogtle Unit Number 4 | Minimum | |||
Public Utility Property Plant and Equipment | |||
Monthly delay cost, exercise of tender option | $ 10 | ||
Vogtle Unit Number 4 | Maximum | |||
Public Utility Property Plant and Equipment | |||
Monthly delay cost, exercise of tender option | $ 15 |
Vogtle Units No. 3 and No. 4 _4
Vogtle Units No. 3 and No. 4 Construction Project - Project Budget and Actual Costs (Details) - Vogtle Units No. 3 & No. 4 - USD ($) $ in Millions | 6 Months Ended | |
Feb. 18, 2019 | Jun. 30, 2023 | |
Actual Costs | ||
Proceeds from guarantee agreement | $ 1,100 | |
Cost sharing benefits | 99 | |
Investment in excess of tender option | 300 | |
Global Amendments To Term Sheet | ||
Project Budget | ||
Totals | 17,100 | |
Actual Costs | ||
Additional construction costs | $ 800 | |
Financial Exposure Term Two | Maximum | Global Amendments To Term Sheet | ||
Actual Costs | ||
Additional construction costs | $ 2,100 | |
Jointly Owned Nuclear Power Plant | ||
Project Budget | ||
Construction Costs | 6,559 | |
Freeze Capital Credit | (532) | |
Financing Costs | 2,038 | |
Subtotal | 8,065 | |
Deferred Training Costs | 47 | |
Total Project Costs Before Contingency | 8,112 | |
Oglethorpe Contingency | 3 | |
Totals | 8,115 | |
Actual Costs | ||
Construction Costs | 6,393 | |
Freeze Capital Credit | 0 | |
Financing Costs | 1,925 | |
Subtotal | 8,318 | |
Deferred Training Costs | 47 | |
Total Project Costs Before Contingency | 8,365 | |
Oglethorpe Contingency | 0 | |
Totals | 8,365 | |
Jointly Owned Nuclear Power Plant | Global Amendments To Term Sheet | ||
Project Budget | ||
Totals | $ 17,100 |
Plant Wansley (Details)
Plant Wansley (Details) | Jul. 31, 2022 |
Plant Wansley | |
Asset Retirement Obligation [Line Items] | |
Ownership interest (as a percent) | 30% |
Asset Retirement Obligations -
Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Thousands | 6 Months Ended | ||
Jun. 30, 2023 | Jun. 30, 2022 | Mar. 31, 2023 | |
Asset Retirement Obligation [Line Items] | |||
Change in asset retirement obligations | $ 87,509 | $ 0 | |
Ashpond and other | |||
Asset Retirement Obligation [Line Items] | |||
Change in asset retirement obligations | $ 24,700 | ||
Vogtle Unit Number 3 | |||
Asset Retirement Obligation [Line Items] | |||
Cost to close plant | $ 62,800 |
Plant Acquisition - Narrative (
Plant Acquisition - Narrative (Details) - Natural Gas Processing Plant $ in Thousands | May 25, 2023 USD ($) unit MW |
Baconton Power LLC | |
Plant Acquisition [Line Items] | |
Number of generating units acquried | unit | 4 |
Generating capacity of each nuclear unit (in megawatts) | MW | 188 |
Baconton Power | |
Plant Acquisition [Line Items] | |
Number of generating units acquried | unit | 1 |
Generating capacity of each nuclear unit (in megawatts) | MW | 47 |
Purchase price of acquisition | $ | $ 16,743 |
Transaction costs | $ | $ 746 |
Remaining life of the plant | 14 years |
Plant Acquisition - Identifiabl
Plant Acquisition - Identifiable Assets Acquired and Liabilities Assumed (Details) - Baconton Power - Natural Gas Processing Plant $ in Thousands | May 25, 2023 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 |