Georgia (State or other jurisdiction ofincorporation or organization) | 58-1211925 (I.R.S. employer identification no.) | | | | Georgia
(State or other jurisdiction of
incorporation or organization) | | 58-1211925
(I.R.S. employer
identification no.) |
2100 East Exchange Place
Tucker, Georgia
(Address of principal executive offices) |
|
30084-5336
(Zip Code) |
| | | | Registrant's telephone number, including area code |
|
(770) 270-7600 | Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes o ☐ No ý ☒ Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý ☒ No o ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o ☐ Accelerated Filer o ☐ Non-Accelerated Filerý (Do not check if a smaller reporting company) ☒ Smaller Reporting Company o ☐ Emerging Growth Company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o ☐ No ý ☒ Securities registered pursuant to Section 12(b) of the Act: | | | | | | | | | | | | | | | | Title of each class: | | Trading Symbol(s) | | Name of each exchange on which registered: | | None | | N/A | | N/A |
Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.The registrant is a membership corporation and has no authorized or outstanding equity securities.
OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2017
2022 | | | | | | | | | | | |
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| | | | | | Page No. |
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| | | | | | | | | | | | | | | | | | | | Unaudited Consolidated Statements of Comprehensive Margin For the Three and Nine Months ended September 30, 2017 and 2016
| |
4 | | | Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin For the Three and NineMonths ended September 30, 20172022 and 2016 2021 | | | | | | | | | | Notes to Unaudited Consolidated Financial Statements | | | | | Management's Discussion and Analysis of Financial Condition and Results of Operations | | | | | Quantitative and Qualitative Disclosures About Market Risk | | | | | | | |
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| | | | | | | | | | | | | Unregistered Sales of Equity Securities and Use of Proceeds | | | | | Defaults Upon Senior Securities | | | | | | | | | | | | | | | | | | |
| |
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as the timing of various regulatory and other actions, future capital expenditures, business strategy, regulatory actions, and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements. Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2016 and under "Risk Factors" in our Form 10-Q for the quarterly period ended June 30, 20172021 and in this quarterly report on Form 10-Q. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur. Any forward-looking statement speaks only as of the date of this quarterly report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to: •cost increases and schedule delays with respect to our capital improvement and construction projects, in particular,such as, the construction of two additional nuclear units at Plant Vogtle;
Vogtle and closure of coal ash ponds; •the resultsresolution of Westinghouse Electric Company LLCany disputes between two or more of the Vogtle co-owners, including the current litigation regarding certain cost-mitigation provisions under the ownership participation agreement; •the duration and WECTEC Global Project Services Inc.'s bankruptcy filingseverity of subsequent waves of the coronavirus ("COVID-19") pandemic and any inability or failure by Toshiba Corporation to performresulting economic disruption and its obligations pursuant to its settlement agreement related to its guarantee of certain of Westinghouse's obligations related toimpact on our business, financial condition, operations, construction projects, including the additional units at Plant Vogtle;
Vogtle, and our members and their service territories; •decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;
•a decision by Georgia Power Company to cancel the additional Vogtle units or a decision by more than 10% of the co-owners of the additional Vogtle units not to proceed with the construction of the additional Vogtle units upon the occurrence of certain material adverse events;
•the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide; •costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts; •legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance; •our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;
•our current inabilityability to receive advances under the U.S. Department of Energy loan guarantee agreement for construction ofconstructing two additional nuclear units at Plant Vogtle;
•the occurrence of certain events that give the Department of Energy the option to require that we repay all amounts outstanding under the loan guarantee agreement with the Department of Energy over a five yearfive-year period and the Department of Energy'sits decision to require such repayment;
•the continued availability of funding from the Rural Utilities Service;
•the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;ii
Table of Contents
•costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;
•legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;
•
increasing debt caused by significant capital expenditures;
•unanticipated changes in capital expenditures, operating expenses and liquidity needs;
•actions by credit rating agencies;
•commercial banking and financial market conditions;
•risks and regulatory requirements related to the ownership and construction of nuclear facilities;
•adequate funding of our nuclear and coal ash pond decommissioning trust funds including investment performance and projected decommissioning costs;
•early retirement of our co-owned coal facilities; •continued efficient operation of our generation facilities by us and third-parties;
•the availability of an adequate and economical supply of fuel, water and other materials;
•reliance on third-parties to efficiently manage, distribute and deliver generated electricity;
•the direct or indirect effect on our business resulting from cyber or physical attacks on us, our members or third-party service providers, vendors or contractors; •acts of sabotage, wars or terrorist activities, including cyber attacks;
•the inability of counterparties to meet their obligations to us, including failure to perform under agreements;
•litigation or legal and administrative proceedings and settlements;
•changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories, including from the development and deployment of distributed generation and energy storage technologies;
•the inability of counterparties to meet their obligations to us, including failure to perform under agreements; •our members' ability to perform their obligations to us; •our members' ability to offer their residential, commercial and industrial customers competitive rates; •changes to protections granted by the Georgia Territorial Act that subject our members to increased competition; •unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation and efficiency efforts and the general economy;
•our members' ability to perform their obligations to us;
•changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;
•general economic conditions;
•weather conditions and other natural phenomena;
•litigation or legal and administrative proceedings and settlements; •unanticipated changes in interest rates or rates of inflation;
•significant changes in our relationship with our employees, including the availability of qualified personnel;
•significant changes in critical accounting policies material to us; and
•hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards.hazards;
•catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events, or similar occurrences; and •other factors discussed elsewhere in this quarterly report or in other reports we file with the SEC.
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
| | | Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
September 30, 20172022 and December 31, 20162021 |
| | | | | | | | | | | | | (dollars in thousands) | | 2022 | | 2021 | | Assets | | | | | Electric plant: | | | | | In service | $ | 9,114,953 | | | $ | 9,865,660 | | | Right-of-use assets—finance leases | 302,732 | | | 302,732 | | | Less: Accumulated provision for depreciation | (5,076,478) | | | (5,565,724) | | | Electric plant in service, net | 4,341,207 | | | 4,602,668 | | | | | | | Nuclear fuel, at amortized cost | 382,933 | | | 375,267 | | | Construction work in progress | 7,457,488 | | | 6,779,392 | | | Total electric plant | 12,181,628 | | | 11,757,327 | | | | | | | Investments and funds: | | | | | Nuclear decommissioning trust fund | 503,452 | | | 659,910 | | | Investment in associated companies | 76,096 | | | 75,826 | | | Long-term investments | 630,411 | | | 711,379 | | | Restricted investments | — | | | 73,702 | | | | | | | Other | 33,330 | | | 31,991 | | | Total investments and funds | 1,243,289 | | | 1,552,808 | | | | | | | Current assets: | | | | | Cash and cash equivalents | 572,828 | | | 579,350 | | | Restricted cash and short-term investments | 141,226 | | | 248,150 | | | Short-term investments | 52,061 | | | — | | | Receivables | 235,656 | | | 159,538 | | | Inventories, at average cost | 270,994 | | | 260,526 | | | Prepayments and other current assets | 99,719 | | | 60,486 | | | Total current assets | 1,372,484 | | | 1,308,050 | | | | | | | Deferred charges and other assets: | | | | | Regulatory assets | 1,314,464 | | | 1,008,790 | | | Prepayments to Georgia Power Company | 19,371 | | | 27,124 | | | Other | 136,192 | | | 52,927 | | | Total deferred charges | 1,470,027 | | | 1,088,841 | | | Total assets | $ | 16,267,428 | | | $ | 15,707,026 | |
| | | | | | | | | | | (dollars in thousands) | | | | 2017 | | 2016 | | Assets | | | | | | | | Electric plant: | | | | | | | | In service | | $ | 8,857,293 | | $ | 8,786,839 | | Less: Accumulated provision for depreciation | | | (4,260,047 | ) | | (4,115,339 | ) | | | | | | | | | | | | | 4,597,246 | | | 4,671,500 | | Nuclear fuel, at amortized cost | | |
360,529 | | |
377,653 | | Construction work in progress | | | 3,824,068 | | | 3,228,214 | | | | | | | | | | | Total electric plant | | | 8,781,843 | | | 8,277,367 | | | | | | | | | | | Investments and funds: | | |
| | |
| | Nuclear decommissioning trust fund | | | 427,786 | | | 386,029 | | Investment in associated companies | | | 74,187 | | | 72,783 | | Long-term investments | | | 125,518 | | | 99,874 | | Restricted investments | | | 265,180 | | | 221,122 | | Other | | | 21,689 | | | 20,730 | | | | | | | | | | | Total investments and funds | | | 914,360 | | | 800,538 | | | | | | | | | | | Current assets: | | |
| | |
| | Cash and cash equivalents | | | 342,064 | | | 366,290 | | Restricted short-term investments | | | 246,432 | | | 247,006 | | Receivables | | | 180,250 | | | 155,042 | | Inventories, at average cost | | | 263,226 | | | 259,831 | | Prepayments and other current assets | | | 20,438 | | | 32,919 | | | | | | | | | | | Total current assets | | | 1,052,410 | | | 1,061,088 | | | | | | | | | | | Deferred charges: | | |
| | |
| | Regulatory assets | | | 572,237 | | | 545,387 | | Other | | | 28,639 | | | 16,733 | | | | | | | | | | | Total deferred charges | | | 600,876 | | | 562,120 | | | | | | | | | | | Total assets | | $ | 11,349,489 | | $ | 10,701,113 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
September 30, 20172022 and December 31, 20162021 |
| | | | | | | | | | | | | (dollars in thousands) | | | | | | 2022 | | 2021 | | Equity and Liabilities | | | | | | | | | Capitalization: | | | | | Patronage capital and membership fees | $ | 1,202,667 | | | $ | 1,130,423 | | | Long-term debt | 11,005,830 | | | 10,529,449 | | | Obligation under finance leases | 57,249 | | | 61,335 | | | Other | 28,449 | | | 27,701 | | | Total capitalization | 12,294,195 | | | 11,748,908 | | | | | | | Current liabilities: | | | | | Long-term debt and finance leases due within one year | 243,585 | | | 281,238 | | | Short-term borrowings | 924,661 | | | 1,095,971 | | | Accounts payable | 192,644 | | | 182,164 | | | Accrued interest | 89,845 | | | 96,410 | | | Member power bill prepayments, current | 46,635 | | | 26,102 | | | Other current liabilities | 144,422 | | | 36,123 | | | Total current liabilities | 1,641,792 | | | 1,718,008 | | | | | | | Deferred credits and other liabilities: | | | | | Asset retirement obligations | 1,388,708 | | | 1,287,143 | | | Member power bill prepayments, non-current | 46,621 | | | 80,001 | | | Regulatory liabilities | 873,549 | | | 849,449 | | | Other | 22,563 | | | 23,517 | | | Total deferred credits and other liabilities | 2,331,441 | | | 2,240,110 | | | Total equity and liabilities | $ | 16,267,428 | | | $ | 15,707,026 | |
| | | | | | | | | | | (dollars in thousands) | | | | 2017 | | 2016 | | Equity and Liabilities | | | | | | | | Capitalization: | | |
| | |
| | Patronage capital and membership fees | | $ | 923,495 | | $ | 859,810 | | Accumulated other comprehensive margin | | | (352 | ) | | (370 | ) | | | | | | | | | | | | | 923,143 | | | 859,440 | | Long-term debt | | |
7,991,307 | | |
7,892,836 | | Obligation under capital lease | | | 89,710 | | | 92,096 | | Other | | | 19,725 | | | 18,765 | | | | | | | | | | | Total capitalization | | | 9,023,885 | | | 8,863,137 | | | | | | | | | | | Current liabilities: | | |
| | |
| | Long-term debt and capital lease due within one year | | | 154,817 | | | 316,861 | | Short-term borrowings | | | 631,949 | | | 102,168 | | Accounts payable | | | 161,168 | | | 73,801 | | Accrued interest | | | 84,287 | | | 93,634 | | Member power bill prepayments, current | | | 43,836 | | | 176,988 | | Other current liabilities | | | 54,621 | | | 59,979 | | | | | | | | | | | Total current liabilities | | | 1,130,678 | | | 823,431 | | | | | | | | | | | Deferred credits and other liabilities: | | |
| | |
| | Asset retirement obligations | | | 726,074 | | | 698,051 | | Member power bill prepayments, non-current | | | 202,202 | | | 48,115 | | Contract retainage | | | 0 | | | 40,008 | | Regulatory liabilities | | | 236,445 | | | 197,748 | | Other | | | 30,205 | | | 30,623 | | | | | | | | | | | Total deferred credits and other liabilities | | | 1,194,926 | | | 1,014,545 | | | | | | | | | | | Total equity and liabilities | | $ | 11,349,489 | | $ | 10,701,113 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Oglethorpe Power Corporation
Consolidated Statements of Revenues and Expenses (Unaudited)
For the Three and Nine Months Ended September 30, 20172022 and 20162021 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months | | Nine Months | | | | | | | | | | | | | 2022 | | 2021 | | 2022 | | 2021 | | | | | | | | | | | | | | | | Operating revenues: | | | | | | | | | | | | | | | | | | | | | | | Sales to members | $ | 627,130 | | | $ | 437,240 | | | $ | 1,523,361 | | | $ | 1,171,433 | | | | | | | | | | | | | | | | | Sales to non-members | 77,135 | | | 23,582 | | | 134,474 | | | 23,847 | | | | | | | | | | | | | | | | | Total operating revenues | 704,265 | | | 460,822 | | | 1,657,835 | | | 1,195,280 | | | | | | | | | | | | | | | | | Operating expenses: | | | | | | | | | | | | | | | | | | | | | | | Fuel | 419,218 | | | 214,681 | | | 847,823 | | | 436,277 | | | | | | | | | | | | | | | | | Production | 114,167 | | | 99,321 | | | 323,334 | | | 298,171 | | | | | | | | | | | | | | | | | Depreciation and amortization | 70,926 | | | 69,758 | | | 212,682 | | | 204,654 | | | | | | | | | | | | | | | | | Purchased power | 21,383 | | | 16,920 | | | 55,919 | | | 50,706 | | | | | | | | | | | | | | | | | Accretion | 14,018 | | | 14,117 | | | 41,410 | | | 41,839 | | | | | | | | | | | | | | | | | Total operating expenses | 639,712 | | | 414,797 | | | 1,481,168 | | | 1,031,647 | | | | | | | | | | | | | | | | | Operating margin | 64,553 | | | 46,025 | | | 176,667 | | | 163,633 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other income: | | | | | | | | | | | | | | | | | | | | | | | Investment income | 15,090 | | | 12,299 | | | 39,762 | | | 36,389 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Other | 3,385 | | | 2,516 | | | 9,510 | | | 4,964 | | | | | | | | | | | | | | | | | Total other income | 18,475 | | | 14,815 | | | 49,272 | | | 41,353 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Interest charges: | | | | | | | | | | | | | | | | | | | | | | | Interest expense | 117,018 | | | 105,201 | | | 333,282 | | | 312,927 | | | | | | | | | | | | | | | | | Allowance for debt funds used during construction | (69,031) | | | (56,179) | | | (188,301) | | | (164,628) | | | | | | | | | | | | | | | | | Amortization of debt discount and expense | 2,944 | | | 2,911 | | | 8,714 | | | 8,677 | | | | | | | | | | | | | | | | | Net interest charges | 50,931 | | | 51,933 | | | 153,695 | | | 156,976 | | | | | | | | | | | | | | | | | Net margin | $ | 32,097 | | | $ | 8,907 | | | $ | 72,244 | | | $ | 48,010 | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | (dollars in thousands) | | | | Three Months | | Nine Months | | | | 2017 | | 2016 | | 2017 | | 2016 | | Operating revenues: | | | | | | | | | | | | | | Sales to Members | | $ | 385,758 | | $ | 430,883 | | $ | 1,106,975 | | $ | 1,158,134 | | Sales to non-Members | | | 148 | | | 130 | | | 220 | | | 383 | | | | | | | | | | | | | | | | | Total operating revenues | | | 385,906 | | | 431,013 | | | 1,107,195 | | | 1,158,517 | | | | | | | | | | | | | | | | | Operating expenses: | | | | | | | | | | | | | | Fuel | | | 143,767 | | | 178,516 | | | 366,405 | | | 404,056 | | Production | | | 93,657 | | | 105,681 | | | 293,930 | | | 312,332 | | Depreciation and amortization | | | 56,143 | | | 54,719 | | | 167,983 | | | 162,606 | | Purchased power | | | 14,345 | | | 13,109 | | | 44,222 | | | 39,254 | | Accretion | | | 9,224 | | | 8,059 | | | 27,333 | | | 24,099 | | | | | | | | | | | | | | | | | Total operating expenses | | | 317,136 | | | 360,084 | | | 899,873 | | | 942,347 | | | | | | | | | | | | | | | | | Operating margin | | | 68,770 | | | 70,929 | | | 207,322 | | | 216,170 | | | | | | | | | | | | | | | | | Other income: | | |
| | |
| | |
| | |
| | Investment income | | | 14,850 | | | 12,578 | | | 44,509 | | | 37,628 | | Other | | | 627 | | | 1,531 | | | 1,908 | | | 6,259 | | | | | | | | | | | | | | | | | Total other income | | | 15,477 | | | 14,109 | | | 46,417 | | | 43,887 | | | | | | | | | | | | | | | | | Interest charges: | | |
| | |
| | |
| | |
| | Interest expense | | | 93,809 | | | 93,544 | | | 280,621 | | | 273,066 | | Allowance for debt funds used during construction | | | (33,517 | ) | | (30,135 | ) | | (99,953 | ) | | (84,460 | ) | Amortization of debt discount and expense | | | 3,150 | | | 2,999 | | | 9,386 | | | 8,946 | | | | | | | | | | | | | | | | | Net interest charges | | | 63,442 | | | 66,408 | | | 190,054 | | | 197,552 | | | | | | | | | | | | | | | | | Net margin | | $ | 20,805 | | $ | 18,630 | | $ | 63,685 | | $ | 62,505 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Oglethorpe Power Corporation
Consolidated Statements of Comprehensive MarginPatronage Capital and Membership Fees (Unaudited)
For the Three and Nine Months Ended September 30, 20172022 and 20162021 |
| | | | | | | (dollars in
thousands) | | Balance at December 31, 2020 | $ | 1,072,642 | | | Net margin | 25,958 | | | Balance at March 31, 2021 | $ | 1,098,600 | | | Net margin | 13,145 | | | Balance at June 30, 2021 | $ | 1,111,745 | | | Net margin | 8,907 | | | Balance at September 30, 2021 | $ | 1,120,652 | | | Balance at December 31, 2021 | $ | 1,130,423 | | | Net margin | 21,980 | | | Balance at March 31, 2022 | $ | 1,152,403 | | | Net margin | 18,167 | | | Balance at June 30, 2022 | $ | 1,170,570 | | | Net margin | 32,097 | | | Balance at September 30, 2022 | $ | 1,202,667 | | | | | | | | | |
| | | | | | | | | | | | | | | | | (dollars in thousands) | | | | Three Months | | Nine Months | | | | 2017 | | 2016 | | 2017 | | 2016 | | Net margin | |
$ |
20,805 | |
$ |
18,630 | |
$ |
63,685 | |
$ |
62,505 | | | | | | | | | | | | | | | | | Other comprehensive margin: | | |
| | |
| | |
| | |
| | Unrealized gain (loss) on available-for-sale securities | | | 56 | | | (19 | ) | | 18 | | | 358 | | | | | | | | | | | | | | | | | Total comprehensive margin | | $ | 20,861 | | $ | 18,611 | | $ | 63,703 | | $ | 62,863 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
| | | Oglethorpe Power Corporation
Consolidated Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive (Deficit) MarginCash Flows (Unaudited)
For the Nine Months Ended September 30, 20172022 and 20162021 |
| | | | | | | | | | | | | (dollars in thousands) | | 2022 | | 2021 | | Cash flows from operating activities: | | | | | Net margin | $ | 72,244 | | | $ | 48,010 | | | Adjustments to reconcile net margin to net cash provided by operating activities: | | | | | Depreciation and amortization, including nuclear fuel | 333,245 | | | 297,976 | | | Accretion cost | 41,410 | | | 41,839 | | | Amortization of deferred gains | (1,341) | | | (1,341) | | | Allowance for equity funds used during construction | (460) | | | (267) | | | Deferred outage costs | (26,712) | | | (27,163) | | | Loss (gain) on sale of investments | 21,077 | | | (11,665) | | | | | | | Regulatory deferral of costs associated with nuclear decommissioning | (45,229) | | | (15,592) | | | Other | 2,352 | | | (639) | | | Change in operating assets and liabilities: | | | | | Receivables | (84,191) | | | (51,283) | | | Inventories | (10,312) | | | 46,686 | | | Prepayments and other current assets | 8,859 | | | (6,199) | | | Accounts payable | 29,464 | | | (4,487) | | | Accrued interest | (6,565) | | | 5,842 | | | Accrued taxes | 51,394 | | | 6,788 | | | Other current liabilities | 47,369 | | | 522 | | | Member power bill prepayments | (12,847) | | | (31,482) | | | Rate management program collections, net | 16,904 | | | 117,600 | | | Total adjustments | 364,417 | | | 367,135 | | | Net cash provided by operating activities | 436,661 | | | 415,145 | | | Cash flows from investing activities: | | | | | Property additions | (872,551) | | | (891,162) | | | Plant acquisition | — | | | (233,156) | | | Activity in nuclear decommissioning trust fund—Purchases | (201,721) | | | (556,879) | | | —Proceeds | 196,136 | | | 550,956 | | | | | | | Decrease in restricted investments | 246,427 | | | 167,607 | | | Activity in other long-term investments—Purchases | (144,843) | | | (340,877) | | | —Proceeds | 103,024 | | | 184,083 | | | Other | 5,569 | | | 8,139 | | | Net cash used in investing activities | (667,959) | | | (1,111,289) | | | Cash flows from financing activities: | | | | | Long-term debt proceeds | 803,032 | | | 517,524 | | | Long-term debt payments | (365,104) | | | (440,548) | | | (Decrease) increase in short-term borrowings, net | (171,310) | | | 639,876 | | | Other | 23,958 | | | 30,124 | | | Net cash provided by financing activities | 290,576 | | | 746,976 | | | Net increase in cash, cash equivalents and restricted cash | 59,278 | | | 50,832 | | | Cash, cash equivalents and restricted cash at beginning of period | 581,150 | | | 405,511 | | | Cash, cash equivalents and restricted cash at end of period | $ | 640,428 | | | $ | 456,343 | | | Supplemental cash flow information: | | | | | Cash paid for— | | | | | Interest (net of amounts capitalized) | $ | 150,208 | | | $ | 141,206 | | | Supplemental disclosure of non-cash investing and financing activities: | | | | | Change in asset retirement obligations | $ | 66,716 | | | $ | 42,964 | | | Accrued property additions at end of period | $ | 45,926 | | | $ | 71,443 | | | | | |
| | | | | | | | | | | | | | | (dollars in thousands) | |
|
|
Patronage
Capital and
Membership
Fees |
|
Accumulated
Other
Comprehensive
(Deficit) Margin |
|
Total |
|
|---|
| Balance at December 31, 2015 | | $ | 809,465 | | $ | 58 | | $ | 809,523 | | | | | | | | | | | | | | | Components of comprehensive margin: | | | | | | | | | | | Net margin | | | 62,505 | | | — | | | 62,505 | | Unrealized gain on available-for-sale securities | | | — | | | 358 | | | 358 | | | | | | | | | | | | | | | Balance at September 30, 2016 | | $ | 871,970 | | $ | 416 | | $ | 872,386 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Balance at December 31, 2016 |
|
$ |
859,810 |
|
$ |
(370 |
) |
$ |
859,440 |
| | | | | | | | | | | | | | Components of comprehensive margin: | | | | | | | | | | | Net margin | | | 63,685 | | | — | | | 63,685 | | Unrealized gain on available-for-sale securities | | | — | | | 18 | | | 18 | | | | | | | | | | | | | | | Balance at September 30, 2017 | | $ | 923,495 | | $ | (352 | ) | $ | 923,143 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The accompanying notes are an integral part of these consolidated financial statements.
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Oglethorpe Power Corporation
Consolidated Statements of Cash Flows (Unaudited)
For the Nine Months Ended September 30, 2017 and 2016
|
| | | | | | | | | | | (dollars in thousands) | | | | 2017 | | 2016 | | Cash flows from operating activities: | | | | | | | | Net margin | | $ | 63,685 | | $ | 62,505 | | | | | | | | | | | Adjustments to reconcile net margin to net cash provided by operating activities: | | | | | | | | Depreciation and amortization, including nuclear fuel | | | 279,898 | | | 268,674 | | Accretion cost | | | 27,333 | | | 24,099 | | Amortization of deferred gains | | | (1,341 | ) | | (1,341 | ) | Allowance for equity funds used during construction | | | (567 | ) | | (567 | ) | Deferred outage costs | | | (32,777 | ) | | (29,464 | ) | Gain on sale of investments | | | (16,478 | ) | | (653 | ) | Regulatory deferral of costs associated with nuclear decommissioning | | | 631 | | | (14,522 | ) | Other | | | (6,610 | ) | | (4,424 | ) | Change in operating assets and liabilities: | | | | | | | | Receivables | | | (24,650 | ) | | (41,015 | ) | Inventories | | | (3,395 | ) | | 30,251 | | Prepayments and other current assets | | | 1,949 | | | (1,305 | ) | Accounts payable | | | 68,585 | | | (87,056 | ) | Accrued interest | | | (9,347 | ) | | (966 | ) | Accrued taxes | | | 7,249 | | | 5,348 | | Other current liabilities | | | (13,354 | ) | | (20,604 | ) | Member power bill prepayments | | | 20,935 | | | 32,809 | | | | | | | | | | | Total adjustments | | | 298,061 | | | 159,264 | | | | | | | | | | | Net cash provided by operating activities | | | 361,746 | | | 221,769 | | | | | | | | | | | Cash flows from investing activities: | | | | | | | | Property additions | | | (737,146 | ) | | (421,384 | ) | Activity in nuclear decommissioning trust fund—Purchases | | | (329,248 | ) | | (307,222 | ) | —Proceeds | | | 323,840 | | | 302,308 | | Increase in restricted investments | | | (44,058 | ) | | (66,821 | ) | Decrease in restricted short-term investments | | | 574 | | | 3,519 | | Activity in other long-term investments—Purchases | | | (45,246 | ) | | (44,457 | ) | —Proceeds | | | 27,196 | | | 35,278 | | Other | | | (12,780 | ) | | 2,401 | | | | | | | | | | | Net cash used in investing activities | | | (816,868 | ) | | (496,378 | ) | | | | | | | | | | Cash flows from financing activities: | | | | | | | | Long-term debt proceeds | | | 4,517 | | | 634,279 | | Long-term debt payments | | | (240,417 | ) | | (113,328 | ) | Increase (decrease) in short-term borrowings, net | | | 652,401 | | | (105,225 | ) | Other | | | 14,395 | | | 8,553 | | | | | | | | | | | Net cash provided by financing activities | | | 430,896 | | | 424,279 | | | | | | | | | | | Net (decrease) increase in cash and cash equivalents | | | (24,226 | ) | | 149,670 | | Cash and cash equivalents at beginning of period | | | 366,290 | | | 213,038 | | | | | | | | | | | Cash and cash equivalents at end of period | | $ | 342,064 | | $ | 362,708 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Supplemental cash flow information: | | | | | | | | Cash paid for— | | | | | | | | Interest (net of amounts capitalized) | | $ | 187,798 | | $ | 185,484 | | Supplemental disclosure of non-cash investing and financing activities: | | | | | | | | Change in asset retirement obligations | | $ | 2,189 | | $ | 72,097 | | Change in accrued property additions | | $ | (21,904 | ) | $ | (24,451 | ) | Interest paid-in-kind | | $ | 42,555 | | $ | 34,587 | |
The accompanying notes are an integral part of these consolidated financial statements.
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Oglethorpe Power Corporation
Notes to Unaudited Consolidated Financial Statements
(A)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, theour financial condition and results of operations for the three-month and nine-month periods ended September 30, 20172022 and 2016.2021. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) revenue recognition, such as determining the nature and timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. 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, 2016,2021, as filed with the SEC. The results of operations for the three-month and nine-month periods ended September 30, 20172022 are not necessarily indicative of results to be expected for the full year. As noted in our 20162021 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 20162021 Form 10-K.
(B)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. None of our financial assets or liabilities had unobservable inputs classifying them as level 3.
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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.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.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 orof comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 20172022 and December 31, 2016.2021. | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at Reporting Date Using | | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | September 30, 2022 | | (Level 1) | | (Level 2) | | (Level 3) | | (dollars in thousands) | | Nuclear decommissioning trust funds: | | | | | | | | | Domestic equity | $ | 189,706 | | | $ | 189,706 | | | $ | — | | | $ | — | | | International equity trust | 97,294 | | | — | | | 97,294 | | | — | | | Corporate bonds and debt | 63,283 | | | — | | | 63,283 | | | — | | | US Treasury securities | 44,191 | | | 44,191 | | | — | | | — | | | Mortgage backed securities | 38,779 | | | — | | | 38,779 | | | — | | | Domestic mutual funds | 52,740 | | | 52,740 | | | — | | | — | | | | | | | | | | | Federal agency securities | 2,958 | | | — | | | 2,958 | | | — | | | Non-US Gov't bonds & private placements | 2,842 | | | — | | | 2,842 | | | — | | | Other | 11,659 | | | 11,659 | | | — | | | — | | | Long-term investments: | | | | | | | | | International equity trust | 29,375 | | | — | | | 29,375 | | | — | | | Corporate bonds and debt | 13,444 | | | — | | | 13,346 | | | 98 | | | US Treasury securities | 11,141 | | | 11,141 | | | — | | | — | | | Mortgage backed securities | 12,725 | | | — | | | 12,725 | | | — | | | Domestic mutual funds | 264,413 | | | 264,413 | | | — | | | — | | | | | | | | | | | Treasury STRIPS | 297,346 | | | — | | | 297,346 | | | — | | | Non-US Gov't bonds & private placements | 1,886 | | | — | | | 1,886 | | | — | | | Other | 81 | | | 81 | | | — | | | — | | | Short-term investments: Treasury STRIPS | 52,061 | | | — | | | 52,061 | | | — | | | Natural gas swaps | 192,026 | | | — | | | 192,026 | | | — | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at Reporting Date Using | | | | | September 30,
2017 | | | Quoted Prices in
Active Markets for
Identical Assets
(Level 1) | | | Significant Other
Observable
Inputs
(Level 2)
| | | | | | | | | | | | | | | | | (dollars in thousands) | | Nuclear decommissioning trust funds: | | | | | | | | | | | Domestic equity | | $ | 138,008 | | $ | 138,008 | | $ | — | | International equity trust | | | 81,260 | | | — | | | 81,260 | | Corporate bonds | | | 68,909 | | | — | | | 68,909 | | US Treasury and government agency securities | | | 51,144 | | | 51,144 | | | — | | Agency mortgage and asset backed securities | | | 35,153 | | | — | | | 35,153 | | Mutual funds | | | 47,604 | | | 47,604 | | | — | | Municipal bonds | | | 301 | | | — | | | 301 | | Other | | | 5,407 | | | 5,407 | | | — | | Long-term investments: | | | | | | | | | | | International equity trust | | | 20,712 | | | — | | | 20,712 | | Corporate bonds | | | 15,173 | | | — | | | 15,173 | | US Treasury and government agency securities | | | 11,608 | | | 11,608 | | | — | | Agency mortgage and asset backed securities | | | 1,348 | | | — | | | 1,348 | | Mutual funds | | | 75,479 | | | 75,479 | | | — | | Other | | | 1,198 | | | 1,199 | | | — | | Natural gas swaps | | | 807 | | | — | | | 807 | | | | | | | | | | | | | | | | | | | | | | | | |
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| | | | | | Fair Value Measurements at Reporting Date Using | | | Fair Value Measurements at Reporting Date Using | | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | | December 31,
2016 | | Quoted Prices in
Active Markets for
Identical Assets
(Level 1) | | Significant Other
Observable
Inputs
(Level 2)
| | | December 31, 2021 | | (Level 1) | | (Level 2) | | (Level 3) | | | | | | | | | | | | | | | (dollars in thousands) | | | (dollars in thousands) | Nuclear decommissioning trust funds: | | | | | | | | Nuclear decommissioning trust funds: | | | | | | | | Domestic equity | | $ | 170,408 | | $ | 170,408 | | $ | — | | Domestic equity | $ | 249,999 | | | $ | 249,999 | | | $ | — | | | $ | — | | International equity trust | | 66,861 | | — | | 66,861 | | International equity trust | 140,718 | | | — | | | 140,718 | | | — | | Corporate bonds | | 60,019 | | — | | 60,019 | | | US Treasury and government agency securities | | 65,725 | | 65,725 | | — | | | Agency mortgage and asset backed securities | | 17,410 | | — | | 17,410 | | | | Corporate bonds and debt | | Corporate bonds and debt | 72,936 | | | — | | | 72,369 | | | 567 | | | US Treasury securities | | US Treasury securities | 53,321 | | | 53,321 | | | — | | | — | | | Mortgage backed securities | | Mortgage backed securities | 40,460 | | | — | | | 40,460 | | | — | | | Domestic mutual funds | | Domestic mutual funds | 75,384 | | | 75,384 | | | — | | | — | | Municipal bonds | | 943 | | — | | 943 | | Municipal bonds | 1,133 | | | — | | | 1,133 | | | — | | | Federal agency securities | | Federal agency securities | 9,608 | | | — | | | 9,608 | | | — | | Other | | 4,663 | | 4,663 | | — | | Other | 16,351 | | | 13,623 | | | 2,728 | | | — | | Long-term investments: | | | | | | | | Long-term investments: | | Corporate bonds | | 11,853 | | — | | 11,853 | | | US Treasury and government agency securities | | 12,187 | | 12,187 | | — | | | Agency mortgage and asset backed securities | | 1,651 | | — | | 1,651 | | | International equity trust | | 15,946 | | — | | 15,946 | | International equity trust | 35,873 | | | — | | | 35,873 | | | — | | Mutual funds | | 57,932 | | 57,932 | | — | | | | Corporate bonds and debt | | Corporate bonds and debt | 14,022 | | | — | | | 12,656 | | | 1,366 | | | US Treasury securities | | US Treasury securities | 15,259 | | | 15,259 | | | — | | | — | | | Mortgage backed securities | | Mortgage backed securities | 12,021 | | | — | | | 12,021 | | | — | | | Domestic mutual funds | | Domestic mutual funds | 277,937 | | | 277,937 | | | — | | | — | | | Federal agency securities | | Federal agency securities | 257 | | | — | | | 257 | | | — | | | Treasury STRIPS | | Treasury STRIPS | 350,532 | | | — | | | 350,532 | | | — | | Other | | 305 | | 305 | | — | | Other | 5,478 | | | 5,478 | | | — | | | — | | Natural gas swaps | | (15,090 | ) | | — | | (15,090 | ) | Natural gas swaps | 63,994 | | | — | | | 63,994 | | | — | | | | | | | | | | | | | | | | |
None of our assets or liabilities measured at
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 recurring basis were categorized asmarket 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 at September 30, 2017 or December 31, 2016.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 September 30, 20172022 and December 31, 20162021 were as follows (in thousands):follows: | | | | | | | | | | | | | | | | | | | | | | | | | 2022 | | 2021 | | Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value | | (in thousands) | | Long-term debt | $ | 11,356,651 | | | $ | 9,585,512 | | | $ | 10,915,054 | | | $ | 12,741,046 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 2017 | | | 2016
| | | | | | | | | | | | | | | | | | | | Carrying
Value | | | Fair
Value | | | Carrying
Value | | | Fair
Value
| | | | | | | | | | | | | | | | | Long-term debt | | $ | 8,237,972 | | $ | 9,119,700 | | $ | 8,304,523 | | $ | 9,043,029 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. 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 September 30, 20172022 and December 31, 2021 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for similar loans.
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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.
- value because of the liquid nature of the deposits with the U.S. Treasury.
(C) Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading 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 for any of these derivatives,to derivative transactions, but instead apply regulatoryregulated 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 hedging 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 September 30, 20172022, all of the counterparties with transaction amounts outstanding under our hedgingderivative 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 hedgederivative 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. Gas hedges.
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.
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At September 30, 20172022 and December 31, 2016,2021, the estimated fair valuevalues of our natural gas contracts was awere net liabilityassets of approximately $807,000$192,026,000 and a net asset of $15,090,000,$63,994,000, respectively. As of September 30, 2017 and December 31, 2016, neither we nor any2022, three of our counterparties were required to post credit support or collateral totaling $67,600,000 under theour natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2017 due toAs of December 31, 2021, one of our credit rating being downgraded below investment grade, we would have beencounterparties was required to post credit collateral or letterstotaling $1,800,000 under our natural gas swap agreements. Such posted collateral is classified as restricted cash and included in the Restricted cash and short-term investments line items within our unaudited consolidated balance sheets.
The following table reflects the notional volume activity of our natural gas derivatives as of September 30, 20172022 that is expected to settle or mature each year: | | | | | | | Year | Natural Gas Swaps (MMBTUs) (in millions) | | 2022 | 5.0 | | | 2023 | 31.0 | | | 2024 | 27.4 | | | 2025 | 23.2 | | | 2026 | 18.2 | | | 2027 | 6.0 | | | Total | 110.8 | |
| | | | | | | | | | | Year | | | Natural Gas Swaps
(MMBTUs)
(in millions)
| | | | | | | | 2017 | | | 3.8 | | 2018 | | | 24.6 | | 2019 | | | 18.7 | | 2020 | | | 15.9 | | 2021 | | | 12.9 | | 2022 | | | 5.8 | | | | | | | | Total | | | 81.7 | | | | | | | |
Interest rate options. In fourth quarter of 2011, we purchased seventeen LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. The last of these options, having a notional value of $80,169,000, expired without value at March 31, 2017.
We are deferring the premiums paid to purchase these LIBOR swaptions, related carrying and other incidental costs in accordance with our rate-making treatment. The deferral will continue and costs will be amortized and collected in rates over the life of the associated debt that we hedged with the swaptions.
The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 20172022 and December 31, 2016.
2021. | | | | | | | | | | | | | | | | Balance Sheet Location | Fair Value | | | 2022 | | 2021 | | | (dollars in thousands) | | Assets: | | | | | | Natural gas swaps | Other current assets | $ | 67,839 | | | $ | 23,596 | | | Natural gas swaps | Other deferred charges | $ | 126,729 | | | $ | 40,398 | | | | | | | | Liabilities: | | | | | | Natural gas swaps | Other current liabilities | $ | 2,542 | | | $ | — | | | Natural gas swaps | Other deferred credits | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | Balance Sheet
Location | | | Fair Value
| | | | | | | | | | | | | | | | | | 2017 | | | 2016 | | | | | | | (dollars in thousands) | | Not designated as hedges: | | | | | | | | | | Assets: | | | | | | | | | | Natural gas swaps | | Other current assets | | $ | 3,302 | | $ | 13,833 | | Natural gas swaps | | Other deferred charges | | $ | — | | $ | 3,289 | | Liabilities: | | | | |
| | |
| | Natural gas swaps | | Other current liabilities | | $ | — | | $ | 54 | | Natural gas swaps | | Other deferred credits | | $ | 4,109 | | $ | 1,977 | | | | | | | | | | | | |
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The following table presents the gross realized gains and (losses) on derivative instruments recognized in marginnet margins for the three and nine months ended September 30, 20172022 and 2016.
2021. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Statement of
Revenues and
Expenses
Location | Three Months Ended
September 30, | | Nine Months Ended September 30, | | | | 2022 | | 2021 | | 2022 | 2021 | | | | | | | (dollars in thousands) | | Natural gas swaps gains | Fuel | $ | 57,639 | | | $ | 15,831 | | | $ | 108,280 | | $ | 18,229 | | | | | | | Natural gas swaps losses | Fuel | (2,995) | | | — | | | (3,277) | | (1,311) | | | | | | | Total | | $ | 54,644 | | | $ | 15,831 | | | $ | 105,003 | | $ | 16,918 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Statement of
Revenues and
Expenses
Location | | | Three months
ended
September 30, | | | Nine months
ended
September 30, | | | | | | | 2017 | | | 2016 | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | Not Designated as hedges: | | | | | | | | | | | | | | | | Natural Gas Swaps | | Fuel | | $ | 778 | | $ | 2,039 | | $ | 3,514 | | $ | 2,057 | | Natural Gas Swaps | | Fuel | | | (678 | ) | | (5,923 | ) | | (1,495 | ) | | (18,262 | ) | | | | | | | | | | | | | | | | | | | | | | $ | 100 | | $ | (3,884 | ) | $ | 2,019 | | $ | (16,205 | ) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at September 30, 20172022 and December 31, 2016. 2021.
| | | | | | | | | | | | | | | | Balance Sheet Location | 2022 | | 2021 | | | (dollars in thousands) | | Natural gas swaps | Regulatory liability | $ | 192,026 | | | $ | 63,994 | | | Total | | $ | 192,026 | | | $ | 63,994 | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | Balance Sheet
Location | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | | | (dollars in thousands) | | Not designated as hedges: | | | | | | | | | | Natural gas swaps | | Regulatory asset | | $ | (2,788 | ) | $ | (62 | ) | Natural gas swaps | | Regulatory liability | | | 1,981 | | | 15,152 | | Interest rate options | | Regulatory asset | | | — | | | (5,788 | ) | | | | | | | | | | | | Total not designated as hedges | | | | $ | (807 | ) | $ | 9,302 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
- (D)
Investments in Debt and EquityInvestment Securities. Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carriedrecorded at marketfair value within the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses net of any tax effect, added to or deducted from other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses fromall investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset.securities. All realized and unrealized gains and losses are determined using the specific identification method. As
The following tables summarize available-for-saledebt and equity securities as of September 30, 20172022 and December 31, 2016.2021. | | | | | | | | | | | | | | | | | | | | | | | | | Gross Unrealized | | (dollars in thousands) | | September 30, 2022 | Cost | | Gains | | Losses | | Fair
Value | | Equity | $ | 315,378 | | | $ | 121,785 | | | $ | (8,879) | | | $ | 428,284 | | | Debt | 799,133 | | | 298 | | | (53,665) | | | 745,766 | | | Other | 11,853 | | | 66 | | | (45) | | | 11,874 | | | Total | $ | 1,126,364 | | | $ | 122,149 | | | $ | (62,589) | | | $ | 1,185,924 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gross Unrealized | | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | September 30, 2017 | | | Cost | | | Gains | | | Losses | | | Fair
Value | | | | | | | | | | | | | | | | | Equity | | $ | 251,021 | | $ | 75,181 | | $ | (4,386 | ) | $ | 321,816 | | Debt | | | 224,458 | | | 2,194 | | | (1,769 | ) | | 224,883 | | Other | | | 6,604 | | | 1 | | | — | | | 6,605 | | | | | | | | | | | | | | | | | Total | | $ | 482,083 | | $ | 77,376 | | $ | (6,155 | ) | $ | 553,304 | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | Gross Unrealized | | (dollars in thousands) | | December 31, 2021 | Cost | | Gains | | Losses | | Fair
Value | | Equity | $ | 304,305 | | | $ | 280,127 | | | $ | (4,682) | | | $ | 579,750 | | | Debt | 774,580 | | | 4,859 | | | (7,001) | | | 772,438 | | | Other | 19,102 | | | — | | | (1) | | | 19,101 | | | Total | $ | 1,097,987 | | | $ | 284,986 | | | $ | (11,684) | | | $ | 1,371,289 | |
Table of Contents
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Gross Unrealized | | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | December 31, 2016 | | | Cost | | | Gains | | | Losses | | | Fair
Value | | | | | | | | | | | | | | | | | Equity | | $ | 237,317 | | $ | 51,054 | | $ | (5,041 | ) | $ | 283,330 | | Debt | | | 201,492 | | | 1,167 | | | (3,423 | ) | | 199,236 | | Other | | | 3,339 | | | — | | | (2 | ) | | 3,337 | | | | | | | | | | | | | | | | | Total | | $ | 442,148 | | $ | 52,221 | | $ | (8,466 | ) | $ | 485,903 | | | | | | | | | | | | | | | | |
- (E)
Recently Issued or Adopted Accounting Pronouncements. In May 2014,March 2020, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers"“Reference Rate Reform (Topic 606)848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting”. The new revenue standard requiresamendments in this update apply to all entities that have contracts, hedging relationships, and other transactions that reference London Interbank Offered Rate (LIBOR) or another reference rate expected to be discontinued because of reference rate reform. The amendments in this update provide optional expedients and exceptions for applying U.S. GAAP to transactions affected by reference rate reform if certain criteria are met. The expedients and exceptions provided by the amendments in this update do not apply to contract modifications made and hedging relationships entered into or evaluated after December 31, 2022, except for hedging relationships existing as of December 31, 2022, for which an entity recognize revenue to depicthas elected certain optional expedients that are retained through the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard was effective for the annual reporting period beginning after December 15, 2016 using eitherend of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption was not permitted. In August 2015,January 2021, the FASB issued an update“Reference Rate Reform (Topic 848): Scope,” to Topic 606 deferringfurther clarify the effective date by one year. The standard is effective for annual reporting periods beginning after December 15, 2017 and interim periods therein. The standard also permits early adoptionscope of the standard, but not before the original effective date of December 15, 2016.While we expect that the majority of our revenues will be includedreference rate reform guidance in Topic 848. The amendments in this update refine the scope of Topic 606, we848 to clarify that certain optional expedients and exceptions therein for contract modifications and hedge accounting apply to contracts that are affected by the discounting transition. Specifically, modifications related to reference rate reform would not be considered an event that requires reassessment of previous accounting conclusions. The amendments in this update also amend the expedients and exceptions in Topic 848 to capture the incremental consequences of the scope clarification and to tailor the existing guidance to derivative instruments affected by the discounting transition.
The amendments in these updates are effective for all entities as of March 12, 2020 through December 31, 2022. We have not fully completed our evaluation of thethis new revenue standard.standard and we do not expect this standard will have a material impact on our consolidated financial statements. (F)Revenue Recognition. As an electric membership cooperative, our principal business is providing wholesale electric service to our members. Our evaluation process includes, but is not limited to, identifying contracts within the scope of Topic 606, reviewing and documenting our accounting for these contracts and assessing the applicability of the variable consideration guidance. A large majority of ouroperating revenues isare derived primarily from substantially identical wholesale power contracts that 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 expect the pattern of revenue recognition pursuantalso 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 September 30, 2022 and December 31, 2021, we did not have any long-term contracts will remain unchangedwith non-members. The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis underbasis. The components of the newformulary 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 standard. However,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 continueexpect to evaluaterecover in a given year and are generally recognized and billed to our members in equal monthly installments over the effects,course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of Topic 606the 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 nine-month periods ended September 30, 2022 and 2021, we provided approximately 62% and 61% of our members' energy requirements, respectively. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2022, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our unaudited consolidated balance sheets. As of September 30, 2022 and September 30, 2021, we recognized refund liabilities totaling $9,022,000 and $16,500,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members.
Sales to members for the three and nine months ended September 30, 2022 and 2021 were as it relatesfollows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | (dollars in thousands) | | | | | | | | | | | | | | 2022 | | 2021 | | 2022 | | 2021 | | | | | | Capacity revenues | $ | 243,860 | | | $ | 228,048 | | | $ | 728,992 | | | $ | 716,303 | | | | | | | Energy revenues | 383,270 | | | 209,192 | | | 794,369 | | | 455,130 | | | | | | | Total | $ | 627,130 | | | $ | 437,240 | | | $ | 1,523,361 | | | $ | 1,171,433 | | | | | | | Member energy requirements supplied | 68 | % | | 65 | % | | 62 | % | | 61 | % | | | | | | | | | | | | | | | | |
Receivables from contracts with our members at September 30, 2022 and December 31, 2021 were $188,951,000 and $143,715,000, respectively. Sales to budget adjustments, which have historically been madenon-members during the fourth quarter but may alsothree and nine months ended September 30, 2022 and 2021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | (dollars in thousands) | | 2022 | | 2021 | | 2022 | | 2021 | | Energy revenues | $ | 77,135 | | | $ | 23,582 | | | $ | 134,474 | | | $ | 23,847 | | | | | | | | | |
Receivables from non-member energy sales at September 30, 2022 and December 31, 2021 were $18,534,000 and $302,000, respectively. Energy revenues from non-members for the three and nine months ended September 30, 2022 were primarily from the sale of a portion of the energy output at Effingham, which we acquired in July 2021, into the wholesale market. For additional information regarding the Effingham acquisition, see Note 13 in our 2021 Form 10-K. There were no capacity revenues from non-members for the three and nine months ended September 30, 2022 and 2021. Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members and have not had a history of any write-offs from non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs associated with the construction of Vogtle Units No. 3 and No. 4, on a current basis, that would otherwise be made during the year that affect ourdeferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual revenue requirement and thereforebasis. Under this program, amounts billed to participating members during the nine months ended September 30, 2022 and 2021 were $11,987,000 and $11,601,000, respectively. The cumulative amount billed since inception of the program totaled $123,623,000. In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. We also continueIn general, the program allows for additional collections over a five-year period with those amounts then applied to evaluate other revenue streams andbillings over the related contracts,subsequent five-year period. The program is designed primarily as well as monitor issues specifica mechanism to assist our members in managing the power and utilities industry. While we have not fully completed our evaluation ofrate impacts associated with the impactcommercial operation of the new revenue recognition guidance,Vogtle units. During the first quarter of 2022, we currently anticipate utilizing a full retrospective transition upon the adoptionbegan applying billing credits to some of Topic 606 as of January 1, 2018.In January 2016, the FASB issued "Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisionsour participating members within this update can be adopted early. Certain provisions withinprogram. Under this update shouldprogram, amounts billed to participating members, net of billing credits, during the nine months ended September 30, 2022, and 2021 were $8,831,000 and $115,837,000, respectively. Funds collected through this program are invested and held until applied to members' bills. Investments that mature and are expected to be applied by means of ato members' bills within the next twelve months are included in the Short-term investments line item within our unaudited consolidated balance sheets. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members' bills. The net cumulative effect adjustment to the balance sheetamount billed, since inception of the fiscal year of adoption and certain provisions should be applied prospectively. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
program totaled $366,159,000.
Table of ContentsIn February 2016, the FASB issued "Leases (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which
(G)Leases. As a lessee, would accountwe have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our four Scherer Unit No. 2 leases as finance leases orand our railcar leases as operating leases. BothWe have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the three and nine months ended September 30, 2022 and 2021 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: •Renew the leases for a period of not less than one year and not more than five years at fair market value, •Purchase the undivided interest at fair market value, or •Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through March 16, 2024. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortizationis at our sole discretion. As all of the ROU asset and forour operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the lessee would recognize a straight-line total lease expense. Theinformation available at the time new lease standard does not substantially change lessor accounting. Theagreements 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, is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018,we combine lease and interim periods therein. Early adoption is permitted. We are currently evaluating the future impact of this standard on our consolidated financial statements.
In June 2016, the FASB issued "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December nonlease components.
| | | | | | | | | | | | | Classification | September 30, 2022 | | December 31, 2021 | | (dollars in thousands) | | Right-of-use assets—Finance leases | | | | | Right-of-use assets | $ | 302,732 | | | $ | 302,732 | | | Less: Accumulated provision for depreciation | (271,559) | | | (267,606) | | | Total finance lease assets | $ | 31,173 | | | $ | 35,126 | | | Lease liabilities—Finance leases | | | | | Obligations under finance leases | $ | 57,249 | | | $ | 61,335 | | | Long-term debt and finance leases due within one year | 7,958 | | | 7,541 | | | Total finance lease liabilities | $ | 65,207 | | | $ | 68,876 | |
15 2019, and interim periods therein. The amendments in this update can be adopted earlier as of the fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. We are currently evaluating the future impact of this standard on our consolidated financial statements.In August 2016, the FASB issued "Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments." The amendments in this standard provide specific guidance on eight cash flow classification issues relating to how certain cash receipts and cash payments are presented and classified in the statement of cash flows, thereby reducing the current and potential future diversity in practice. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. If an entity early adopts the amendments in an interim period, any adjustments should be reflected as of the beginning of the fiscal year that includes that interim period. An entity that elects early adoption must adopt all of the amendments in the same period. The amendments should be applied using a retrospective transition method to each period presented. If it is impracticable to apply the amendments retrospectively for some of the issues, the amendments for those issues would be applied prospectively as of the earliest date practicable. We do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
In November 2016, the FASB issued "Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force)." The amendments in this standard require the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts shown on the statement of cash flows. The new standard is effective for us on a retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods therein. Early adoption is permitted, including adoption in an interim period. Our restricted cash balances are nominal and accordingly we do not expect the adoption of this standard to have a material impact on our consolidated financial statements.
(F)Accumulated Comprehensive Margin. The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin. There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2016
| | | | | | | | | | | | | Classification | September 30, 2022 | | December 31, 2021 | | (dollars in thousands) | | Right-of-use assets—Operating leases | | | | | Electric plant in service, net | $ | 1,664 | | | $ | 2,293 | | | Total operating lease assets | $ | 1,664 | | | $ | 2,293 | | | Lease liabilities—Operating leases | | | | | Capitalization—Other | $ | 960 | | | $ | 1,550 | | | Other current liabilities | 718 | | | 838 | | | Total operating lease liabilities | $ | 1,678 | | | $ | 2,388 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended | | Nine months ended | | | | Lease Cost | Classification | September 30, 2022 | | September 30, 2021 | | September 30, 2022 | | September 30, 2021 | | | | | | | (dollars in thousands) | | Finance lease cost: | | | | | | | | | | | | | | Amortization of leased assets | Depreciation and amortization | $ | 1,885 | | | $ | 1,693 | | | $ | 5,656 | | | $ | 4,726 | | | | | | | Interest on lease liabilities | Interest expense | 1,852 | | | 2,045 | | | 5,556 | | | 6,133 | | | | | | | Operating lease cost: | Inventory(1) & production expense | 222 | | | 270 | | | 666 | | | 809 | | | | | | | Total leased cost | | $ | 3,959 | | | $ | 4,008 | | | $ | 11,878 | | | $ | 11,668 | | | | | |
(1) The majority of our operating lease costs relate to net marginour railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the table belowinventories are reflected in "Other income" on our unaudited Consolidated Statements of Revenues and Expenses.Our effective tax rate is zero; therefore, all amounts below are presented net of tax.
consumed. | | | | | | | | | | | | | September 30, 2022 | | December 31, 2021 | | Lease Term and Discount Rate: | | | | | Weighted-average remaining lease term (in years) | | | | | Finance leases | 6.17 | | 6.90 | | Operating leases | 9.88 | | 8.01 | | Weighted-average discount rate: | | | | | Finance leases | 11.05 | % | | 11.05 | % | | Operating leases | 4.97 | % | | 4.73 | % |
| | | | | | | | | | | | | | Accumulated Other
Comprehensive
(Deficit) Margin | | | | | Three Months Ended
September 30, 2016 | | | | | | | | | | | (dollars in thousands) | | | | | Available-for-sale
Securities | | | | | | | | Balance at June 30, 2016 | | $ | 435 | | Unrealized gain | | |
50 | | (Gain) reclassified to net margin | | |
(69 |
) | | | | | | | Balance at September 30, 2016 | | $ | 416 | | | | | | | |
| | | | | | | | | | | | | Nine months ended September 30, | | 2022 | | 2021 | | (dollars in thousands) | | Other Information: | | | | | Cash paid for amounts included in the measurement of lease liabilities | | | | | Operating cash flows from finance leases | $ | 3,806 | | | $ | 4,180 | | | Operating cash flows from operating leases | $ | 747 | | | $ | 890 | | | Financing cash flows from finance leases | $ | 3,669 | | | $ | 3,295 | | | Right-of-use assets obtained in exchange for new operating lease liabilities | $ | — | | | $ | — | |
| | | | | | | | Three Months Ended
September 30, 2017 | | | | | | | | | | | (dollars in thousands) | | | | | Available-for-sale
Securities | | | | | | | | Balance at June 30, 2017 | |
$ |
(408 |
) | Unrealized gain | | |
33 | | Loss reclassified to net margin | | |
23 | | | | | | | | Balance at September 30, 2017 | | $ | (352 | ) | | | | | | | | | | | | | | | | | |
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Maturity analysis of our finance and operating lease liabilities as of September 30, 2022 is as follows: | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | Year Ending December 31, | Finance Leases | | Operating Leases | | Total | | 2022 | $ | 7,475 | | | $ | 182 | | | $ | 7,657 | | | 2023 | 14,949 | | | 708 | | | 15,657 | | | 2024 | 14,949 | | | 234 | | | 15,183 | | | 2025 | 14,949 | | | 72 | | | 15,021 | | | 2026 | 14,949 | | | 72 | | | 15,021 | | | Thereafter | 25,634 | | | 940 | | | 26,574 | | | Total lease payments | $ | 92,905 | | | $ | 2,208 | | | $ | 95,113 | | | Less: imputed interest | (27,698) | | | (530) | | | (28,228) | | | Present value of lease liabilities | $ | 65,207 | | | $ | 1,678 | | | $ | 66,885 | |
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 nine months ended September 30, 2022 and 2021 was as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine Months Ended September 30, | | | 2022 | | 2021 | | 2022 | | 2021 | | | | | (dollars in thousands) | | | | | Lease income | $ | 1,651 | | | $ | 1,603 | | | $ | 4,965 | | | $ | 4,806 | | | | |
| | | | | | | | | | | | | | Nine Months Ended
September 30, 2016 | | | | | | | | | | | (dollars in thousands) | | | | | Available-for-sale
Securities | | | | | | | | Balance at December 31, 2015 | |
$ |
58 | | Unrealized gain | | |
486 | | (Gain) reclassified to net margin | | |
(128 |
) | | | | | | | Balance at September 30, 2016 | | $ | 416 | | | | | | | |
| | | | | | | | Nine Months Ended
September 30, 2017 | | | | | | | | | | | (dollars in thousands) | | | | | Available-for-sale
Securities | | | | | | | | Balance at December 31, 2016 | |
$ |
(370 |
) | Unrealized loss | | |
(57 |
) | Loss reclassified to net margin | | |
75 | | | | | | | | Balance at September 30, 2017 | | $ | (352 | ) | | | | | | | | | | | | | | | | | |
(G)- (H)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. a. Patronage Capital Litigation
On June 9, 2017, the Georgia Court of Appeals upheld the Superior Court of DeKalb County's decision to dismiss on all counts both of the cases described under Note 12—Patronage Capital Litigation in our 2016 Form 10-K. The plaintiffs did not further appeal these dismissals to the Georgia Supreme Court and the appeal period has since expired, ending this litigation.
b. Environmental MattersMatters. 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 aremay also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.In general, these and other types of environmental requirements have become increasingly stringent. 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
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environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.
At this time, the ultimate impact of any potential new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs. Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent. (H)
In July 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer, of which we are a co-owner, have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief. Georgia
Power has filed multiple motions to dismiss the complaint. On October 8, 2021, three additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power alleging that releases from Plant Scherer, have impacted groundwater and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages. On November 11, 2021, Georgia Power filed a notice to remove the three cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. On February 7, 2022, four additional complaints were filed in the Superior Court of Monroe County, Georgia against Georgia Power seeking damages for alleged personal injuries or property damage. On March 9, 2022, Georgia Power filed notices to remove the four additional cases pending in the Superior Court of Monroe County to the U.S. District Court in the Middle District of Georgia. Collectively, these cases include approximately 70 plaintiffs. The amount of any possible losses from these matters cannot be estimated at this time.
In May 2022, Florida Power & Light Company and JEA filed a complaint in the U.S. District Court for the Northern District of Georgia against us and the other co-owners of Plant Scherer alleging that their contractual responsibility for a proportionate share of certain common facility costs relating to future environmental projects at Plant Scherer should be decreased following the retirement of Scherer Unit No. 4 at the end of 2021. We and the other co-owners of Plant Scherer have filed motions to dismiss Florida Power & Light and JEA's complaint. While we do not believe that the co-ownership agreements support the arguments raised by Florida Power & Light Company and JEA, if their arguments were to be successful in this case, we could be responsible for an increased percentage of these costs relating to our interests in Scherer Unit Nos. 1 and 2. The amount of additional costs relating to these future projects, if any, cannot be determined at this time. (I)Restricted Cash and Investments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account.Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earnFor the period from January 1, 2021 to September 30, 2021, deposits earned interest at a4% per annum. Beginning October 1, 2021, the rate was set at the 1-year floating treasury rate, which was 0.09% per annum, and will be reset annually on October 1 of 5%each year thereafter. On October 1, 2022, the rate was reset at the 1-year floating treasury rate, which was 4.05% per annum. The program no longer allows additional funds to be deposited into the account. At September 30, 20172022 and December 31, 2016,2021, we had restricted investments totaling $511,612,000$73,282,000 and $468,179,000,$320,052,000, respectively, of which $265,180,000$73,282,000 and $221,122,000,$246,350,000, respectively, were classified as long-term.current. Restricted cash consists of collateral posted by our counterparties under our natural gas swap agreements. The funds on deposit withfollowing table provides a reconciliation of cash, cash equivalents and restricted cash reported within the Rural Utilities Serviceunaudited consolidated balance sheets that sum to the total of the same such amounts reported in the Cushionunaudited consolidated statements of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.(I)- cash flows.
| | | | | | | | | | | | | | | | Classification | | | | Nine months ended | | | September 30, 2022 | | September 30, 2021 | | | (dollars in thousands) | | | Cash and cash equivalents | $ | 572,828 | | | $ | 452,943 | | | | | | | | | Restricted cash included in restricted cash and short-term investments | 67,600 | | | 3,400 | | | | Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows | $ | 640,428 | | | $ | 456,343 | | |
(J)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 extendingmembers. 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 unaudited consolidated balance sheets as of September 30, 20172022 and December 31, 2016.2021. | | | | | | | | | | | | | 2022 | | 2021 | | (dollars in thousands) | | Regulatory Assets: | | | | | Premium and loss on reacquired debt(a) | $ | 30,498 | | | $ | 33,200 | | | Amortization of financing leases(b) | 32,476 | | | 34,179 | | | Outage costs(c) | 33,301 | | | 31,956 | | | Asset retirement obligations—Ashpond and other(l) | 411,072 | | | 335,231 | | | Asset retirement obligations—Nuclear(l) | 65,148 | | | — | | | Depreciation expense - Plant Vogtle(d) | 35,905 | | | 36,973 | | | Depreciation expense - Plant Wansley(e) | 366,770 | | | 204,891 | | | Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) | 54,488 | | | 55,857 | | | Interest rate options cost(g) | 135,434 | | | 131,556 | | | Deferral of effects on net margin—Smith Energy Facility(h) | 138,216 | | | 142,675 | | | Other regulatory assets(o) | 11,156 | | | 2,272 | | | Total Regulatory Assets | $ | 1,314,464 | | | $ | 1,008,790 | | | Regulatory Liabilities: | | | | | Accumulated retirement costs for other obligations(i) | $ | 35,905 | | | $ | 22,197 | | | Deferral of effects on net margin—Hawk Road Energy Facility(h) | 16,790 | | | 17,253 | | | Deferral of effects on net margin—Effingham Energy Facility(p) | 20,764 | | | — | | | Major maintenance reserve(j) | 97,745 | | | 73,059 | | | Amortization of financing leases(b) | 6,282 | | | 8,457 | | | Deferred debt service adder(k) | 150,615 | | | 138,897 | | | Asset retirement obligations—Nuclear(l) | — | | | 164,256 | | | Revenue deferral plan(m) | 352,115 | | | 359,799 | | | Natural gas hedges(n) | 192,026 | | | 63,994 | | | Other regulatory liabilities(o) | 1,307 | | | 1,537 | | | Total Regulatory Liabilities | $ | 873,549 | | | $ | 849,449 | | | Net Regulatory Assets | $ | 440,915 | | | $ | 159,341 | | | | | |
| | | | | | | | | | | | | | | | | | | | 2017 | | | 2016 | | | | | (dollars in thousands)
| | | | | | | | | | | Regulatory Assets: | | | | | | | | Premium and loss on reacquired debt(a) | | $ | 51,546 | | $ | 55,084 | | Amortization on capital leases(b) | | | 33,454 | | | 32,274 | | Outage costs(c) | | | 42,060 | | | 39,986 | | Interest rate swap termination fees(d) | | | 2,231 | | | 3,570 | | Asset retirement obligations—Ashpond and other(l) | | | 59,540 | | | 33,747 | | Depreciation expense(e) | | | 43,023 | | | 44,091 | | Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) | | | 47,322 | | | 43,444 | | Interest rate options cost(g) | | | 110,915 | | | 107,394 | | Deferral of effects on net margin—Smith Energy Facility(h) | | | 167,941 | | | 172,399 | | Other regulatory assets(m) | | | 14,205 | | | 13,398 | | | | | | | | | | | Total Regulatory Assets | | $ | 572,237 | | $ | 545,387 | | Regulatory Liabilities: | | |
| | |
| | Accumulated retirement costs for other obligations(i) | | $ | 14,235 | | $ | 9,829 | | Deferral of effects on net margin—Hawk Road Energy Facility(h) | | | 19,705 | | | 20,163 | | Major maintenance reserve(j) | | | 43,269 | | | 28,379 | | Amortization on capital leases(b) | | | 20,780 | | | 23,084 | | Deferred debt service adder(k) | | | 93,296 | | | 86,082 | | Asset retirement obligations(l) | | | 40,199 | | | 11,766 | | Other regulatory liabilities(m) | | | 4,961 | | | 18,445 | | | | | | | | | | | Total Regulatory Liabilities | | $ | 236,445 | | $ | 197,748 | | | | | | | | | | | Net Regulatory Assets | | $ | 335,792 | | $ | 347,639 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
- (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
2722 years.
(b)Represents the difference between expense recognized for rate-making purposes andversus financial statement purposes related to capitalfinance 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 a 24-month period.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 toor 24-month operating cycles of each unit.
(d)Represents losses on settled interest rate swap arrangements that are being amortized through the end of 2018.
(e)
(e)Represents the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which occurred in August 2022. Amortization commenced in September 2022 and will end no later than December 31, 2040. (f)Deferred charges consist of training related to Vogtle Units No. 3costs, including interest and No. 4 training and interest related 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 costs associated withpremiums paid to purchase interest rate options purchasedused to hedge interest rates on certain borrowings, related tocarrying costs and other incidentals associated with construction of Vogtle Units No.3No. 3 and No.4 construction thatNo. 4. Amortization will be amortized over the life of the associated debt.
- commence when Vogtle Unit No. 3 is placed in service.
(h)Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant.
(i)Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.
(j)Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.
(k)Represents collections to fund certain debt payments to be made through the end of 2025 which will be in excess of amounts collected through depreciation expense; the deferred credits will be amortized over the remaining useful life of the plants.
(l)Represents the difference in the timing of recognition of thedecommissioning costs of decommissioning for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for ratemaking purposes.
- decommissioning.
(m)Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings, per each members' election, over the subsequent five-year period. (n)Represents the deferral of unrealized gains on natural gas contracts. (o)The amortization periodperiods for other regulatory assets range up to 3328 years and the amortization periodperiods of other regulatory liabilities range up to 105 years.
Table(p)Effects on net margin for the Effingham Energy Facility that are being deferred until on or before January 2026 and will be amortized over the remaining life of Contents
(J)- the plant.
(K)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 January 2022,December 2026, with the majority of the balance scheduled to be credited by the end of 2019.(K)- 2023.
a) Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, (the Title XVII Loan Guarantee Program), 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 (as amended, the Loan Guarantee Agreement) pursuant to which the Department of Energy agreed to guarantee our obligations under thea 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 Credit Facility Documents). The 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 Credit FacilityNote and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a multi-advance term loan facility (the Facility) , under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility will beare used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Aggregate borrowingsloan guarantee program (Eligible Project Costs). Borrowings under the Facility mayOriginal FFB Notes could not exceed the lesser of (i) 70% of eligible project costs or (ii) $3,057,069,461, of which $335,471,604 iswas designated for capitalized interest. We have advanced all amounts available under the Original FFB Notes. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original FFB Notes due to timing of borrowing and lower than expected interest rates. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in late 2017. At September 30, 2022, borrowings under the Additional FFB Note totaled $1,262,000,000. At September 30, 2022, aggregate Department of Energy-guaranteed borrowings, including capitalized interest, totaled $4,275,348,382. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energyit is required to make any payments to the Federal Financing Bank under theits 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 notes and obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments will beginon all advances under the FFB Notes began on February 20, 2020. Under bothAs of September 30, 2022, we have repaid $280,458,000 of principal on the FFB Notes, the interestNotes. Interest rates on advances during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. At September 30, 2017, aggregate Department
Future advances under the Facility will be permitted unless and until such time as Georgia Power, on behalf of the Co-owners (as defined in Note L), has (i) completed comprehensive schedule, cost-to-complete, and cancellation cost assessments (the Cost Assessments) and made a determination to continue construction of Vogtle Units No. 3 and No. 4; (ii) delivered to the Department of Energy an updated project schedule, construction budget, and other information; (iii) entered into one or more agreements with a construction contractor or contractors that will be primarily responsible for construction of Vogtle Units No. 3 and No. 4 and such agreements have been approved by the Department of Energy (together with the Services Agreement (as defined in Note L) and certain
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related intellectual property licenses (the IP Licenses), the Replacement EPC Arrangements); and (iv) entered into a further amendment to the Loan Guarantee Agreement with the Department of Energy to reflect the Replacement EPC Arrangements.
When the conditions in the preceding paragraph are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020. The timing of satisfaction of these conditions is currently uncertain but likely to be satisfied in 2018. In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, includingas well as (i) certification of compliance with the requirements of the Title XVII Loan Guarantee Program,loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, our continued(iv) no Project Adverse Event (as described in Note M) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note M) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted underEnergy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Loan Guarantee Agreement,Cargo Preference Act, as amended, (vi) evidence of compliance with the prevailingapplicable wage requirements of the Davis-Bacon Act, as amended, and(vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs.
Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement.
We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. Under the Loan Guarantee Agreement, upon the occurrence of
If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy may require usEnergy's option the Federal Financing Bank's commitment to prepaymake further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all guaranteed borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii)(iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, under(iv) termination of the IP Licenses, (iii) a decisionServices Agreement by us notWestinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to continuethe Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 (iv) Georgia Power, on behalfcoupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners fails to complete the Cost Assessments or enter into a replacement contract with respect to the Replacement EPC Arrangements by December 31, 2017, (v)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, (vi)(x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vii)(xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (viii)(xii) change of control of Oglethorpe and (ix)(xiii) certain events of loss or condemnation.Under certain circumstances we may be required to make prepayments in connection with our receipt of payments under the settlement agreement with Toshiba regarding the Toshiba Guarantee or from the EPC Contractor under the EPC Agreement (as defined in Note L). In addition, if If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility.
We may also voluntarily prepay outstanding borrowings under the Facility. Under the FFB Credit Facility Documents, any prepayment will be subject to a make-whole premium or discount, as applicable.
On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1,620,000,000 in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.
b) For the nine-month period ended September 30, 20172022, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $4,517,000$63,031,000 for long-term financing of general and
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environmental improvements at existing plants.These advances are secured under our first mortgage indenture. plants.
On October 30, 2017,18, 2022, we closed on a second Rural Utilities Service-guaranteed loan for $234,681,000 to fund a portion of our cost to acquire Effingham. On October 20, 2022, we received an additional $17,582,000$19,532,000 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 On OctoberApril 12, 2017, the Development Authority2022, we issued $500,000,000 of Burke County (Georgia), the Development Authority of Heard County (Georgia) and the Development Authority of Monroe County (Georgia) issued, on our behalf, $122,620,000 in aggregate principal amount of tax-exempt pollution control revenue4.50% first mortgage bonds, Series 2022A, for the purpose of refinancing costs associatedproviding long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. In conjunction with certainthe issuance of our air or water pollution control and sewage or solid waste disposal facilities.the bonds, we repaid $493,405,000 of outstanding commercial paper. The bonds were directly purchased by a bank and the proceeds were used to repay outstanding commercial paper issued to redeem certain auction rate pollution control revenue bonds in January 2017. Each series of bonds bear interest at an indexed variable rate until October 3, 2022, the initial mandatory tender date. The pollution control revenue bonds are scheduleddue to mature in 2040 through 2045. Our payment obligations related to these bondsApril 2047 and are secured under our first mortgage indenture. (L)
d)Pollution Control Revenue Bonds:
We redeemed $31.0 million of Series 2017 pollution control revenue bonds in the third quarter of 2022. At June 30, 2022, these bonds were classified as long-term debt based upon the contractual maturity date.
(M)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. Our binding ownership interest and proportionate share of the cost to construct these units is 30%. 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. (collectively, the EPC Contractor). Stone & Webster, which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC)(collectively, Westinghouse). Pursuant to the EPC Agreement, the EPC ContractorWestinghouse 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. Under the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations
Until March 2017, construction on Units No. 3 and adjustments. The EPC Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million.Toshiba Corporation guaranteed certain payment obligations of the EPC ContractorNo. 4 continued under the EPC Agreement (the Toshiba Guarantee), including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Co-owners $920��million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under thesubstantially fixed price EPC Agreement. TheIn March 2017, Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the EPC Agreement, the EPC Contractor did not have the right to terminate the EPC Agreement for convenience. In the event of an abandonment of work by the EPC
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Contractor, the maximum liability of the EPC Contractor under the EPC Agreement was 40% of the contract price, or $3.68 billion, of which our proportionate share is approximately $1.1 billion.
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. To provide for a continuation of work at Vogtle Units No. 3 and No. 4, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with the EPC Contractor and WECTEC Staffing Services LLC, which the bankruptcy court approved on March 30, 2017. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Co-owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired onEffective in July 27, 2017.
Subsequent to the EPC Contractor's bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Co-owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which our proportionate share totals approximately $115 million. As of September 30, 2017, $340 million of this aggregate liability had been paid or accrued by Georgia Power, on behalf of the Co-owners.
On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (the Guarantee Obligations), of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Execution of any such transaction cannot be assured and would require certain consents from and cooperation by the Department of Energy.
On November 9, 2017, Toshiba released its financial results for the second quarter of fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of
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September 30, 2017. Toshiba also reiterated the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and the EPC ContractorWestinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), for the EPC Contractorpursuant to transition construction management of Vogtle Units No. 3which Westinghouse is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement.materials cost basis. The Services Agreement became effective upon approval by the Department of Energy on July 27, 2017 andprovides 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.
On August 31, 2017, Georgia Power filed its 17th Vogtle Construction Monitoring report (VCM 17 Report) with the Georgia Public Service Commission.
In the VCM 17 Report, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission will render a decision on these matters by February 6, 2018.The revised project schedule Georgia Power submitted to the Georgia Public Service Commission for approval included commercial operation dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Based on comprehensive cost-to complete assessments and the revised commercial operation dates, our revised project budget is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget assumes 100% recovery of our $1.1 billion share of the Guarantee Obligations from Toshiba. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion without taking into account any amounts recoverable from Toshiba. Amounts recovered in connection with the Guarantee Settlement Agreement will be recorded as a reduction to the construction work in progress balance as payments are received.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement (the Bechtel Agreement) with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4. Facility design4 (the Bechtel Agreement) and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, (not jointly)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
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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. On November 2, 2017, the Co-owners entered into an amendment to their joint
Cost and Schedule Our current budget for our ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interestsinterest in Vogtle Units No. 3 and No. 4, must vote to continuewhich includes capital costs, allowance for funds used during construction if certain adverse events occur, including: (i)and some level of contingency is $8.1 billion and is based on commercial operation dates of March 2023 and March 2024 for Units No. 3 and No. 4, respectively. This budget reflects our June 17, 2022 exercise of the bankruptcy of Toshiba or, excepttender option in the case in which each of the Co-owners has assigned its rights under the Guarantee Settlement Agreement to a third party, a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relatingGlobal Amendments to the constructionJoint Ownership Agreements as described below. Had we not exercised the tender option, our budget would be approximately $8.6 billion. At September 30, 2022, our total investment for our interest in the additional Vogtle units was approximately $7.7 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 will not be recoveredreach commercial operation.
Our initial ownership interest and proportionate share of the cost to construct the additional Vogtle units was 30%, representing approximately 660 megawatts. However, we have exercised the tender option discussed below which caps our capital costs in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increaseexchange for a proportionate reduction of our 30% interest in the constructiontwo units. Based on the current project budget contained inand schedule and our interpretation of the seventeenth VCM reportGlobal Amendments (described below), we would transfer approximately 50 megawatts, out of more than $1 billion or extension660 megawatts, to Georgia Power. Our resulting ownership share would decline from 30% to approximately 28%. However, if the total project budget exceeds the current budget, our ownership share and megawatts would be further reduced. The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, provides additional margin to cover potential cost, schedule, containedand financing risks associated with our share of the project. At the end of the project, if there is remaining Oglethorpe-level contingency, we will adjust our project budget to remove this contingency and bill our members based on the actual project costs. The table below shows our project budget and
actual costs through September 30, 2022 for our share of the project. | | | | | | | | | | | | | | | | | | | (in millions) | | | | Project Budget (Tender) | | Actual Costs at
September 30, 2022 | Construction Costs (1) | | | $ | 6,025 | | | $ | 6,000 | | | Financing Costs | | | 1,974 | | | 1,695 | | | Subtotal | | | $ | 7,999 | | | $ | 7,695 | | | | | | | | | Deferred Training Costs | | | 49 | | | 46 | | | Total Project Costs Before Contingency | | | $ | 8,048 | | | $ | 7,741 | | | | | | | | | Oglethorpe-Level Contingency | | | 52 | | | — | | | | | | | | | Total Contingency | | | $ | 52 | | | $ | — | | | Totals | | | $ | 8,100 | | | $ | 7,741 | | | | | | | | (1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements. |
Any schedule extension beyond March 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $30 million per month for both units and approximately $13 million per month for Unit No. 4. As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the seventeenth VCM reportareas of more than one year. In addition, pursuantengineering support, commodity installation, system turnovers and related test results and workforce statistics. Since March 2020, the number of active cases of COVID-19 at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion. As of September 30, 2022, the incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity, substantially all of which occurred during 2020 and 2021, is estimated by Georgia Power to be between $350 million and $438 million and is included in the Joint Ownership Agreements,project budget. Subsequent waves of the required approval of holders of ownership interests inCOVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4 is at least (i) 90%4.
On July 29, 2022, Southern Nuclear announced that all Unit No. 3 inspections, tests, analyses, and acceptance criteria documentation had been submitted to the Nuclear Regulatory Commission. On August 3, 2022, the Nuclear Regulatory Commission published its 103(g) finding that the acceptance criteria in the combined license for a changeUnit No. 3 had been met, which allowed for nuclear fuel to be loaded and allows start-up testing to begin. Fuel load for Unit No. 3 was completed on October 17, 2022. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 by the end of the primary construction contractorfirst quarter of 2023. Our current budget reflects our expectation of an in-service date for Unit No. 3 in March 2023. The projected schedule for Unit No. 3 primarily depends on the pace of system and (ii) 67% for material amendmentsarea transitions to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor,operations, including the Bechtel Agreement.The effectivenesscompletion of closure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures.
Georgia Power has disclosed that it projects an in-service date for Unit No. 4 by the end of the amendmentsfourth quarter 2023. Given the remaining work to be done and potential risks associated with completing the Joint Ownership Agreementswork, our current budget anticipates an in-service date for Unit No. 4 that is one quarter later, in March 2024. Meeting the projected in-service date for Unit No. 4 primarily depends on Unit No. 3 progress through start-up and testing, overall construction productivity and production levels significantly improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. As Unit No. 4 progresses through construction and continues to transition into testing, ongoing and potential future challenges include the pace and quality of electrical, mechanical, and instrumentation and controls commodities installation; availability of craft and supervisory resources, including the temporary diversion of such resources to support Unit No. 3; the pace of work package closures and system turnovers; and the timeframe and duration of hot functional and other testing.
Ongoing or future challenges for both units also include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity; ability to attract and retain craft labor, and/or related
cost escalation. New challenges also may arise, particularly as Units No. 3 and No. 4 move into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures or components (some of which are based on new technology that only within the Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of April 21, 2006, as amended, is subject to the condition that we obtain the approval of the Rural Utilities Service as required under our loan contract with the Rural Utilities Service.In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investmentlast few years began initial operation in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.
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 as construction proceeds.arise. Processes are in place that are designed to assureensure 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. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending beforeOn March 25, 2022, the Nuclear Regulatory Commission.Commission completed a follow up inspection related to the November 2021 final significance report on its special inspection to review the root cause of additional construction remediation work identified in 2021 and Southern Nuclear’s corresponding corrective action plans. The Nuclear Regulatory Commission closed the findings identified in November 2021 and returned Unit No. 3 to the Nuclear Regulatory Commission’s baseline inspection program.
With the receipt of the Nuclear Regulatory Commission’s 103(g) finding, Unit No. 3 is now under the Nuclear Regulatory Commission’s operating reactor oversight process and must meet applicable technical and operational requirements contained within Unit No. 3’s operating license. Various design and other licensing-based compliance matters, including the timely resolutioncompletion of Inspections, Tests, Analyses,inspections, tests, analyses, and Acceptance Criteriaacceptance criteria documentation and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel for Unit No. 4, may arise, if construction proceeds, which may result in additional license amendmentsamendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria for Unit No. 4, are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs.As construction continues,costs to the risk remains that challenges with management of contractors, subcontractors and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
Co-owners. The ultimate outcome of these matters cannot be determined at this time.
Co-Owner Contracts and Other Information
In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 to provide for, among other conditions, additional Co-owner approval requirements. These joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further on September 26, 2018 by the Term Sheet that was memorialized on February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) to the Joint Ownership Agreements (as amended, the Joint Ownership Agreements). As a result of an increase in the total project capital cost forecast and Georgia Power’s decision not to seek recovery of its allocation of the increase in the base capital costs and the increased construction budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring report (VCM 19) in 2018, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners unanimously voted to continue construction of Vogtle Units No. 3 and No. 4. In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC to mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that: •each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's VCM 19 filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs;
•Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and
•Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $1.6 billion to $2.1 billion (resulting in
up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest). If the EAC is revised and exceeds the EAC in VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, has a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s share of construction costs actually incurred in excess of the EAC in VCM 19 plus $2.1 billion. If any Co-owner elects to exercise this tender option, Georgia Power would have the option to cancel the project in lieu of accepting the offer to purchase a portion of the Co-owner’s ownership interest. If Georgia Power does not elect to cancel the project, then Georgia Power must accept the offer, and the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the percentage of the cumulative amount of construction costs paid by such tendering Co-owner as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of the tendering Co-owner in accordance with the second and third bullets above will be treated as payments made by that Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a proportionate reduction of our 30% ownership interest. The VCM 19 total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. As of December 31, 2021, budget increases since VCM 19 have reached $3.4 billion for all Co-owners. As a result of these increases, we believe that the tender option was triggered at the Co-owner construction budget vote on February 14, 2022 and that Georgia Power’s increased responsibility for certain construction costs as described above commenced in March 2022.
On June 17, 2022, we notified Georgia Power of our election to exercise the tender option and cap our capital costs in exchange for a proportionate reduction of our 30% interest in the two new units. Our decremental ownership interest will be calculated and conveyed to Georgia Power after both Vogtle units are placed in service. Based on the current project budget, our schedule assumptions and our interpretation of the Global Amendments, our project budget is $8.1 billion and we expect to transfer approximately 50 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately 28%. By exercising the tender option and based on current assumptions, we estimate that we will avoid incurring approximately $500 million in construction costs associated with the project. However, if the total project budget exceeds the current budget, our ownership share and megawatts would be further reduced. On July 26, 2022, the City of Dalton notified Georgia Power that it had elected to exercise its tender option.
We and Georgia Power do not agree on certain aspects of the tender option, including the dollar amount that triggers our option to tender a portion of our ownership interest to Georgia Power under the tender option or the extent to which costs that are the result of a force majeure event (such as COVID-19) impact the point at which the tender option is triggered. For purposes of determining when our option to tender has been triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. We and Georgia Power also do not agree on the dollar amount that triggers Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above is triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in the nineteenth VCM report by $800 million to $2.1 billion.
Accordingly, in March 2022, we notified Georgia Power of a billing dispute with regards to both the starting dollar amount and the application of costs resulting from a force majeure event and how such amounts impact the thresholds and timing of the cost-sharing and tender option provisions. On June 18, 2022, after completing the dispute resolution procedures set forth in the Ownership Participation Agreement for the additional Vogtle units, we and MEAG filed separate lawsuits against Georgia Power in the Superior Court of Fulton County, Georgia seeking to enforce the terms of the Global Amendments. 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 $8.6 billion, an increase of approximately $500 million, and we would retain 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. See “Item 1A – RISK FACTORS” in our 2021 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units (N)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.
(O)Plant Wansley. In July 2022, the Georgia Public Service Commission approved Georgia Power’s 2022 integrated resource plan. This plan requested the decertification of coal-fired Plant Wansley, of which we own a 30% interest, by August 31, 2022. In accordance with the approved plan, Georgia Power retired Plant Wansley in August 2022. Beginning in 2021, we accelerated depreciation of the remaining plant in service assets associated with Plant Wansley based upon the August 2022 retirement date and created a regulatory asset to defer a portion of the accelerated depreciation expense. These deferred costs will be recovered through future rates over a period ending no later than December 31, 2040. The Georgia Public Service Commission also approved Georgia Power’s modified closure proposal for the ash pond at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Wansley, beneficial use of the coal ash, and managing construction and operational risks of the previous close in place design. The Georgia Environmental Protection Department must also approve the change in closure plans. We and Georgia Power are continuing to evaluate the costs associated with the modified closure plan; however, we have received preliminary estimates from Georgia Power. At September 30, 2022, we have recognized an additional $66.7 million in coal ash related asset retirement obligations based upon these preliminary cost estimates. We expect to receive more refined estimates from Georgia Power regarding closure costs and the timing of expenditures prior to year-end 2022. See Note J of Notes to Unaudited Consolidated Financial Statements for additional information regarding the retirement of Plant Wansley and the associated regulatory asset and see “Item 1 – OUR BUSINESS – REGULATION – Environmental – Coal Combustion Residuals and Effluent Limitations Guidelines” in our 2021 Form 10-K for additional information regarding the closure of the coal ash pond.
(P)Subsequent Events. On October 24, 2022, we entered into an agreement to acquire two generating units at Washington County Power, a four-unit 660 megawatt combustion turbine generation and transmission facility located in Sandersville, Georgia, from Gulf Pacific Power, LLC, an investment fund managed by Harbert Management Corporation. The two acquired units will add approximately 330 megawatts of natural gas-fired capacity to our generation portfolio. This acquisition is subject to customary closing conditions, including regulatory approvals, and is expected to close in the fourth quarter of 2022.
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from other suppliers. As with cooperatives generally, we operate on a not-for-profit basis. Results of Operations For the Three and Nine Months Ended September 30, 2022 and 2021 For the Three and Nine Months Ended September 30, 2017 and 2016
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Net Margin Our net margins for the three-month and nine-month periods ended September 30, 20172022 were $20.8$32.1 million and $63.7$72.2 million, respectively, compared to $18.6$8.9 million and $62.5$48.0 million, respectively, for the same periods of 2016.2021. Through September 30, 2017,2022, we collected approximately 123%117.1% of our targeted net margin of $51.7$61.7 million for the year ending December 31, 2017.2022. These collections are typical as our capacity revenues are generally recorded evenly throughout the year and our management budgets conservatively. In September 2017, our board of directors approved a budget adjustment that reduced revenue requirements by $5.0 million in order to provide our members with a measure of relief for costs they incurred as a result of significant system damage from Hurricane Irma.year. We anticipate our board of directors will approve an additionala budget adjustment by theyear end of the year so that margins will achieve, but not exceed, our 2017the 2022 targeted margins for interest ratio of 1.14. As a result, we assessed our projected margin and annual revenue requirement to meet the targeted margins for interest ratio to determine if a refund liability should be recognized. As a result of this assessment, we recognized cumulative refund liabilities of $9.0 million and $16.5 million as of September 30, 2022 and September 30, 2021, respectively. For additional information regarding our net margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" in our 20162021 Form 10-K.
Our operating 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, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.suppliers and sales to non-members. Sales to Members. We generate revenues principally from the sale of electric capacity and energy to our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity, andelectricity. These revenues are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by sellingthe sales of electricity to our members, which involves generatinggenerated or purchasing electricitypurchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.
Table of Contents
The components of member revenues for the three-month and nine-month periods ended September 30, 20172022 and 20162021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | | | (dollars in thousands) | | | | (dollars in thousands) | | | | | | | 2022 | | 2021 | | % Change | | 2022 | | 2021 | % Change | | | | | | | | Capacity revenues | $ | 243,860 | | | $ | 228,048 | | | 6.9 | % | | $ | 728,992 | | | $ | 716,303 | | 1.8 | % | | | | | | | | Energy revenues | 383,270 | | | 209,192 | | | 83.2 | % | | 794,369 | | | 455,130 | | 74.5 | % | | | | | | | | Total | $ | 627,130 | | | $ | 437,240 | | | 43.4 | % | | $ | 1,523,361 | | | $ | 1,171,433 | | 30.0 | % | | | | | | | | MWh Sales to members | 8,243,846 | | | 7,566,980 | | | 8.9 | % | | 20,053,117 | | | 18,727,189 | | 7.1 | % | | | | | | | | Cents/kWh | 7.61 | | | 5.78 | | | 31.7 | % | | 7.60 | | | 6.26 | | 21.4 | % | | | | | | | | Member energy requirements supplied | 68 | % | | 65 | % | | 4.6 | % | | 62 | % | | 61 | % | 1.6 | % | | | | | | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | | | | | (dollars in thousands) | | | | | | | | 2017 | | | 2016 | | | | | | 2017 | | | 2016 | | | | | | | | | | | | | | | | | | | | | | | | | | Capacity revenues | | $ | 217,918 | | $ | 228,011 | | | (4.4%) | | $ | 666,226 | | $ | 681,384 | | | (2.2%) | | Energy revenues | | | 167,840 | | | 202,872 | | | (17.3%) | | | 440,749 | | | 476,750 | | | (7.6%) | | | | | | | | | | | | | | | | | | | | | | | Total | | $ | 385,758 | | $ | 430,883 | | | (10.5%) | | $ | 1,106,975 | | $ | 1,158,134 | | | (4.4%) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | MWh Sales to members | | | 6,962,978 | | | 7,956,412 | | | (12.5%) | | | 18,213,379 | | | 19,886,944 | | | (8.4%) | | Cents/kWh | | | 5.54 | | | 5.42 | | | 2.3% | | | 6.08 | | | 5.82 | | | 4.4% | | Member energy requirements supplied | | |
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CapacityEnergy revenues from members increased for the three-month and nine-month periods ended September 30, 2017 reflect a $5.0 million reduction2022 compared to the same periods in revenue requirements for2021, primarily due to the September 2017 budget adjustment approved by the boardrecovery of directors discussed above.
Energy revenues fromfuel costs. The increase in megawatt-hours sold to members decreased for the three-month and nine-month periods ended September 30, 20172022 compared to the same periods in 20162021 also contributed to the increase in energy revenues, primarily due to a decrease in fuel costs which was largely a result of a decrease in generation for member sales in 2017.slightly warmer weather and members' consumer growth. For a discussion of fuel costs, which are the primary components ofcosts recovered by energy revenues, see "—Operating Expenses."
TableSales to non-members. Energy revenues from non-members were primarily from the sale of Contentsa portion of the energy output at Effingham, which we acquired in July 2021, into the wholesale market. There were no capacity revenues from non-members for the three-month and nine-month periods ended September 30, 2022 and 2021. Sales to non-members during the three-month and nine-month periods ended September 30, 2022 and 2021 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | | Nine Months Ended
September 30, | | | (dollars in thousands) | | | (dollars in thousands) | | | | | | | | | | | | | 2022 | | 2021 | % Change | | 2022 | | 2021 | % Change | | Energy revenues | $ | 77,135 | | | $ | 23,582 | | 227.1 | % | | $ | 134,474 | | | $ | 23,847 | | 463.9 | % | | MWh Sales to non-members | 694,911 | | | 562,724 | | 23.5 | % | | 1,450,107 | | | 575,629 | | 151.9 | % | | Cents/kWh | 11.10 | | | 4.19 | | 164.9 | % | | 9.27 | | | 4.14 | | 123.9 | % |
Energy revenues from non-members increased for the three-month and nine-month periods ended September 30, 2022 compared to the same periods in 2021 primarily due to higher market prices and an increase in megawatt-hours sold to non-members. Fuel The following table summarizes our fuel costs and megawatt-hour generation by generating source. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Cost | | Generation | | Cents per kWh | | (dollars in thousands) | | (MWh) | | | | | | | | Three Months Ended
September 30, | | | | Three Months Ended
September 30, | | | | Three Months Ended
September 30, | | | | Fuel Source | 2022 | | 2021 | | % Change | | 2022 | | 2021 | | % Change | | 2022 | | 2021 | | % Change | | Coal | $ | 35,908 | | | $ | 50,384 | | | (28.7)% | | 984,046 | | | 1,535,053 | | | (35.9)% | | 3.65 | | | 3.28 | | | 11.3% | | Nuclear | 19,492 | | | 18,849 | | | 3.4% | | 2,692,666 | | | 2,434,355 | | | 10.6% | | 0.72 | | | 0.77 | | | (6.5)% | | Gas: | | | | | | | | | | | | | | | | | | | Combined Cycle | 263,871 | | | 121,220 | | | 117.7% | | 4,350,220 | | | 3,885,404 | | | 12.0% | | 6.07 | | | 3.12 | | | 94.6% | | Combustion Turbine | 99,947 | | | 24,228 | | | 312.5% | | 1,110,747 | | | 489,436 | | | 126.9% | | 9.00 | | | 4.95 | | | 81.8% | | $ | 419,218 | | | $ | 214,681 | | | 95.3% | | 9,137,679 | | | 8,344,248 | | | 9.5% | | 4.59 | | | 2.57 | | | 78.6% | | | | | | | | | | | | | | | | | | | | Cost | | Generation | | Cents per kWh | | (dollars in thousands) | | (MWh) | | | | | | | | Nine Months Ended
September 30, | | | | Nine Months Ended
September 30, | | | | Nine Months Ended
September 30, | | | | Fuel Source | 2022 | | 2021 | | % Change | | 2022 | | 2021 | | % Change | | 2022 | | 2021 | | % Change | | Coal | $ | 88,681 | | | $ | 86,061 | | | 3.0% | | 2,425,508 | | | 2,559,235 | | | (5.2)% | | 3.66 | | | 3.36 | | | 8.9% | | Nuclear | 54,678 | | | 57,853 | | | (5.5)% | | 7,516,956 | | | 7,529,053 | | | (0.2)% | | 0.73 | | | 0.77 | | | (5.2)% | | Gas: | | | | | | | | | | | | | | | | | | | Combined Cycle | 561,460 | | | 252,472 | | | 122.4% | | 10,422,541 | | | 8,876,229 | | | 17.4% | | 5.39 | | | 2.84 | | | 89.8% | | Combustion Turbine | 143,004 | | | 39,891 | | | 258.5% | | 1,671,317 | | | 873,175 | | | 91.4% | | 8.56 | | | 4.57 | | | 87.3% | | $ | 847,823 | | | $ | 436,277 | | | 94.3% | | 22,036,322 | | | 19,837,692 | | | 11.1% | | 3.85 | | | 2.20 | | | 75.0% |
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September 30, | | | 2017 vs. | | | Three Months Ended
September 30, | | | 2017 vs. | | | Three Months Ended
September 30, | | | 2017 vs.
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coal | | $ | 30,924 | | $ | 49,478 | | | (37.5%) | | | 1,157,960 | | | 1,704,203 | | | (32.1%) | | | 2.67 | | | 2.90 | | | (8.0%) | | Nuclear | | | 23,249 | | | 21,950 | | | 5.9% | | | 2,585,668 | | | 2,691,129 | | | (3.9%) | | | 0.90 | | | 0.82 | | | 10.2% | | Gas: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Combined Cycle | | | 67,058 | | | 73,223 | | | (8.4%) | | | 2,888,612 | | | 2,976,562 | | | (3.0%) | | | 2.32 | | | 2.46 | | | (5.6%) | | Combustion Turbine | | | 22,536 | | | 33,865 | | | (33.5%) | | | 544,294 | | | 846,699 | | | (35.7%) | | | 4.14 | | | 4.00 | | | 3.5% | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 143,767 | | $ | 178,516 | | | (19.5%) | | | 7,176,534 | | | 8,218,593 | | | (12.7%) | | | 2.00 | | | 2.17 | | | (7.8%) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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September 30, | | | 2017 vs. | | | Nine Months Ended
September 30, | | | 2017 vs. | | | Nine Months Ended
September 30, | | | 2017 vs.
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% Change
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Coal | | $ | 81,867 | | $ | 114,961 | | | (28.8%) | | | 2,913,161 | | | 3,945,663 | | | (26.2%) | | | 2.81 | | | 2.91 | | | (3.5%) | | Nuclear | | | 66,538 | | | 61,786 | | | 7.7% | | | 7,399,354 | | | 7,605,266 | | | (2.7%) | | | 0.90 | | | 0.81 | | | 10.7% | | Gas: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Combined Cycle | | | 181,254 | | | 165,272 | | | 9.7% | | | 7,546,775 | | | 7,338,407 | | | 2.8% | | | 2.40 | | | 2.25 | | | 6.6% | | Combustion Turbine | | | 36,746 | | | 62,037 | | | (40.8%) | | | 881,514 | | | 1,644,184 | | | (46.4%) | | | 4.17 | | | 3.77 | | | 10.5% | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | $ | 366,405 | | $ | 404,056 | | | (9.3%) | | | 18,740,804 | | | 20,533,520 | | | (8.7%) | | | 1.96 | | | 1.97 | | | (0.6%) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total fuel costs decreasedincreased for the three-month and nine-month periods ended September 30, 20172022 compared to the same periods in 2021 as a result of an increase in the average cost of fuel and an increase in generation for members and non-members. In
June 2022, our member system hit a new peak demand of 10,018 megawatts, eclipsing our members' prior peak of 9,477 megawatts. The increase in average fuel cost was primarily due to higher average natural gas prices in 2022 as prices have increased due to supply and demand pressures. The overall increase in generation for the three-month and nine-month periods ended September 30, 2022 compared to the same periods in 2021 was largely due to our members obtaining more of their energy requirements from us rather than their third party suppliers due to relative energy prices and an increase in sales to non-members. Production Production costs increased for the three-month and nine-month periods ended September 30, 2022 as compared to the same periods of 20162021 primarily due to a decrease in generation as a result of moderate temperatures. In addition, generationdeferring Effingham's effects on net margin of $17.8 million and $24.5 million, respectively. For additional information regarding the Effingham deferral, see Note 13 in our 2021 Form 10-K. Interest Charges Net interest charges decreased slightly for the three-month and nine-month periods ended September 30, 2022 as compared to the same periods of 2021 as a result of the capitalization of interest expense associated with construction expenditures for Vogtle Units No. 3 and No. 4.
Financial Condition Balance Sheet Analysis as of September 30, 2022 Assets Electric plant in service decreased $750.7 million for the nine-month period ended September 30, 2017 compared2022, primarily due to the sameretirement of $870.3 million of Plant Wansley assets, including the coal ash pond, in August 2022, offset partially by additions to plant of $157.4 million. Accumulated provision for depreciation decreased $489.2 million also primarily as a result of the $870.3 million Plant Wansley retirement, partially offset by depreciation recorded for the nine-month period which included $271.3 million of 2016 was somewhat affected by increased natural gas pricesPlant Wansley depreciation. In anticipation of the plant's early retirement, we created a regulatory asset in 2021 to defer a portion of the accelerated depreciation expense. See Notes J and planned maintenance outages during 2017.O of Notes to Unaudited Consolidated Financial Condition Statements for a discussion of the regulatory asset associated with the early retirement of Plant Wansley. Balance Sheet Analysis as of September 30, 2017
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Assets
Cash used for property additions for the nine-month period ended September 30, 20172022 totaled $737.1$872.6 million. Of this amount, approximately $518.5$686.1 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 $47.7and $60.2 million was for nuclear fuel purchases andpurchases. The remainder was for expenditures forrelated to normal additions and replacements to our existing generation facilities. The $156.5 million decrease in nuclear decommissioning trust fund was primarily due to the decrease in the fair market value of trust assets due to the downturn in the stock market during the nine-month period ended September 30, 2022. Long-term investments decreased $81.0 million for the nine-month period ended September 30, 2022 primarily due to a $66.0 million decrease in fair market value of our long-term investments during the nine-month period ended September 30, 2022. In addition, $52.1 million of investments associated with one of our rate management programs was reclassified to short-term investments as we expect to apply the proceeds from these maturing investments to members' bills during the next twelve months. Offsetting these decreases were $20.5 million of collections and fund earnings invested in our major maintenance outage, coal ash remediation and internal decommissioning funds and $16.6 million in net collections invested under one of our member rate programs during the nine-month period ended September 30, 2022. See Note F of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs. Restricted cash and investments consist of $67.6 million in collateral posted by our counterparties under our natural gas swap agreements and $73.3 million in funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The funds, including interest earned thereon,We can only be applied to debt service on ourutilize the restricted investments in the Cushion of Credit Account for future Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisionsdebt service payments. The program no longer allows additional funds to be deposited into the account. During the nine-month period ended September 30, 2022, restricted cash and investments decreased $180.6 million as we utilized $246.9 million for debt service payments and expect to utilize the remainder of the balance through 2023. The decrease in restricted investments was offset by a $65.8 million increase in restricted cash posted by counterparties under our natural gas swap agreements. For additional information regarding whenrestricted cash and investments, see Note I of Notes to apply the funds are guided by the interest rate environment and our anticipated liquidity needs.Unaudited Consolidated Financial Statements.
Receivables increased $76.1 million for the nine-month period ended September 30, 2022 primarily due to a $46.4 million increase in member revenues and LiabilitiesLong-term debta $26.9 million increase in other receivables. Other receivables increased $98.5primarily due to $18.2 million of trade receivables related to non-member sales and $8.2 million from related parties.
Prepayments and other current assets increased $39.2 million during the nine-month period ended September 30, 20172022 primarily due to a $44.2 million increase in fair value of our natural gas contracts that will settle within the classificationnext twelve months and an increase of $122.6$3.1 million in collateral we were required to post with a counterparty under our natural gas purchase and sale agreements. Offsetting these increases was a decrease of commercial paper$11.9 million in prepaid inventory primarily relating to return of refurbished inventory associated with a major maintenance outage at one of our combined cycle plants. Regulatory assets increased $305.7 million largely as long-term debt. In October 2017, $122.6a result of a $161.9 million increase in the deferral of tax-exempt bondsaccelerated depreciation associated with the early retirement of Plant Wansley, which occurred in August 2022. The increase in our regulatory assets was issuedalso attributable to refunda $76.0 million increase in the commercial paper ondeferral associated with coal ash pond asset retirement obligations and a long-term basis. For information regarding$65.1 million increase in the refunding of commercial paper and the issuance of tax-exempt bonds, see Note K.Long-term debt and capital leases due within one year decreased $162.0deferral associated with nuclear asset retirement obligations.
Other deferred charges increased $83.3 million during the nine-month period ended September 30, 2017. The decrease was2022 primarily due to an $86.3 million increase in fair value of our natural gas contracts that will settle after the next twelve months. Equity and Liabilities Long-term debt and long-term debt and finance leases due within one year increased $438.7 million primarily as a result of the issuance of $500.0 million of Series 2022A first mortgage bonds, a $168.0 million advance under the Department of Energy-guaranteed loan and $63.0 million in advances under the Rural Utilities Service-guaranteed loan. Offsetting this increase was $258.5 million in debt service payments and the early redemption of $122.6$31.0 million of variable rateSeries 2017 pollution control revenue bonds through the issuancebonds. See Note L of commercial paper in January 2017. In addition, the decrease was dueNotes to certain quarterly Federal Financing Bank note payments we made, when due, in early January 2017.Unaudited Consolidated Financial Statements for additional information regarding long-term debt. Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased $529.8decreased $171.3 million during the nine-month period ended September 30, 2017.2022 primarily as a result of $493.4 million in repayments made from the proceeds of the first mortgage bonds issuance noted above. During this period, total short-term repayments were $1.0 billion and borrowings totaled $832.7 million. Accounts payable increased $87.4$10.5 million forduring the nine-month period ended September 30, 20172022. The increase was primarily asdue to a result of a $104.7$76.6 million increase in the payablepayables for natural gas purchases and related transportation and a $9.2 million increase in payables to Georgia Power Company for operation and maintenance costs for our co-owned plants and capital costs associated with Vogtle Units No. 3 and No. 4.related parties. Offsetting thethis increase was $17.2a decrease of $41.7 million in trade accounts payable, primarily for property taxes, and the application of $30.0 million in credits applied to our members' bills in the first quarter of 2017,2022 for a board approvedboard-approved reduction in 20162021 revenue requirements as a result of margins in excess of our 2016 target.Thethe requirement to meet the 2021 targeted net margin.
Other current portion of member power bill prepayments decreased $133.2liabilities increased $108.3 million for the nine-month period ended September 30, 20172022 primarily as a result of a $65.8 million increase in restricted cash posted by and due to the application of credits against the power bills of members that participatecounterparties under our natural gas swap agreements and a $48.6 million increase in the power bill prepayment program. The long-term portion of member power bill prepaymentsaccrued property taxes. Regulatory liabilities increased $154.1$24.1 million for the nine-month period ended September 30, 20172022 primarily due to member contributions to$128.0 million increase in the program made duringliability associated with unrealized gains on our natural gas contracts, a $24.7 million increase in sinking fund collections for future major maintenance outages and a $21.3 million increase in the third quarterliability associated with the deferral of 2017.Effingham's effects on net margin. Partially offsetting this increase was a $164.3 million decrease in the liability associated with deferred nuclear asset retirement obligations that was primarily driven by a decrease in unrealized gains associated with our nuclear decommissioning investments. For additional information onregarding the member power bill prepayment program,Effingham deferral, see Note J13 in our 2021 Form 10-K. Asset retirement obligations increased $101.6 million for the nine-month period ended September 30, 2022 primarily due to change in cash flow estimates of Notes$66.7 million related to Unaudited Consolidated Financial Statements.coal ash pond decommissioning and $41.4 million in accretion expense. Capital Requirements and Liquidity and Sources of Capital Capital Requirements and Liquidity and Sources of Capital
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Vogtle Units No. 3 and No. 4 We, Georgia Power, the Municipal Electric Authority of Georgia (MEAG), and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our binding ownership interest and proportionate share of the cost to construct these units is 30%. 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. (collectively, the EPC Contractor). Stone & Webster, which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC)(collectively, Westinghouse). Pursuant to the EPC Agreement, the EPC ContractorWestinghouse 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.
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Under the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalationsUntil March 2017, construction on Units No. 3 and adjustments. The EPC Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million.
Toshiba Corporation guaranteed certain payment obligations of the EPC ContractorNo. 4 continued under the EPC Agreement (the Toshiba Guarantee), including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Co-owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under thesubstantially fixed price EPC Agreement. TheIn March 2017, Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners, in the event the Westinghouse Letters of Credit will not be renewed.
Under the terms of the EPC Agreement, the EPC Contractor did not have the right to terminate the EPC Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the EPC Agreement was 40% of the contract price, or $3.68 billion, of which our proportionate share is approximately $1.1 billion.
On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. To provide for a continuation of work at Vogtle Units No. 3 and No. 4, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with the EPC Contractor and WECTEC Staffing Services LLC, which the bankruptcy court approved on March 30, 2017. The Interim Assessment Agreement provided, among other items, that during the term of the Interim Assessment Agreement Georgia Power was obligated to pay, on behalf of the Co-owners, all costs accrued by the EPC Contractor for subcontractors and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired onEffective in July 27, 2017.
Subsequent to the EPC Contractor's bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken, and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Co-owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386 million, of which our proportionate share totals approximately $115 million. As of September 30, 2017, $340 million of this aggregate liability had been paid or accrued by Georgia Power, on behalf of the Co-owners.
On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (the Guarantee Obligations), of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the
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balance of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Execution of any such transaction cannot be assured and would require certain consents from and cooperation by the Department of Energy.
On November 9, 2017, Toshiba released its financial results for the second quarter of the fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of September 30, 2017. Toshiba also reiterated the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.
Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and the EPC ContractorWestinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), for the EPC Contractorpursuant to transition construction management of Vogtle Units No. 3which Westinghouse is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement.materials cost basis. The Services Agreement became effective upon approval by the Department of Energy on July 27, 2017 andprovides 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.
On August 31, 2017, Georgia Power filed its 17th Vogtle Construction Monitoring report (VCM 17 Report) with the Georgia Public Service Commission. In the VCM 17 Report, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission is expected to render a decision on these matters by February 6, 2018.The revised project schedule Georgia Power submitted to the Georgia Public Service Commission for approval included commercial operation dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Based on comprehensive cost-to complete assessments and the revised commercial operation dates, our revised project budget is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget assumes 100% recovery of our $1.1 billion share of the Guarantee Obligations from Toshiba. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion without taking into account any amounts recoverable from Toshiba. Amounts recovered in connection with the Guarantee Settlement Agreement will be recorded as a reduction to the construction work in progress balance as payments are received.
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Based on the revised project schedule and budget, the following table provides an updated estimate of our forecasted capital expenditures related to Vogtle Units No. 3 and No. 4 for 2017 through 2019 (dollars in millions).
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| | | | | | | | | | | | | | | | | | 2017 | | | 2018 | | | 2019 | | | Total
| | | | | | | | | | | | | | | | | Future Generation | | $ | 645 | | $ | 677 | | $ | 504 | | $ | 1,826 | | | | | | | | | | | | | | | | |
In addition to the amounts reflected in the table above, we have budgeted approximately $1.9 billion to complete construction of Vogtle Units No. 3 and No. 4 beyond the years shown in the table. These projected capital expenditures assume that Toshiba fully performs its obligations under the Guarantee Settlement Agreement and the failure of Toshiba to perform those obligations could have a material impact on our costs for Vogtle Units No. 3 and No. 4. For additional information regarding our capital expenditures, see "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements—Capital Expenditures" in our 2016 Form 10-K.
Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement (the Bechtel Agreement) with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4. Facility design4 (the Bechtel Agreement) and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, (not jointly)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.
On November 2, 2017, the Co-owners entered into an amendment to their joint
Cost and Schedule Our current budget for our ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interestsinterest in Vogtle Units No. 3 and No. 4, must vote to continuewhich includes capital costs, allowance for funds used during construction if certain adverse events occur, including: (i)and some level of contingency is $8.1 billion and is based on commercial operation dates of March 2023 and March 2024 for Units No. 3 and No. 4, respectively. This budget reflects our June 17, 2022 exercise of the bankruptcy of Toshiba or, excepttender option in the case in which each of the Co-owners has assigned its rights under the Guarantee Settlement Agreement to a third party, a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relatingGlobal Amendments to the constructionJoint Ownership Agreements as described below. Had we not exercised the tender option, our budget would be approximately $8.6 billion. At September 30, 2022, our total investment for our interest in the additional Vogtle units was approximately $7.7 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 will not be recoveredreach commercial operation.
Our initial ownership interest and proportionate share of the cost to construct the additional Vogtle units was 30%, representing approximately 660 megawatts. However, we have exercised the tender option discussed below which caps our capital costs in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increaseexchange for a proportionate reduction of our 30% interest in the constructiontwo units. Based on the current project budget contained inand schedule and our interpretation of the seventeenth VCM reportGlobal Amendments (described below), we would transfer approximately 50 megawatts, out of more than $1 billion or extension660 megawatts, to Georgia Power. Our resulting ownership share would decline from 30% to approximately 28%. However, if the total project budget exceeds the current budget, our ownership share and megawatts would be further reduced.
The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, provides additional margin to cover potential cost, schedule, containedand financing risks associated with our share of the project. At the end of the project, if there is remaining Oglethorpe-level contingency, we will adjust our project budget to remove this contingency and bill our members based on the actual project costs. The table below shows our project budget and actual costs through
September 30, 2022 for our share of the project. | | | | | | | | | | | | | | | | | | | (in millions) | | | | Project Budget (Tender) | | Actual Costs at
September 30, 2022 | Construction Costs (1) | | | $ | 6,025 | | | $ | 6,000 | | | Financing Costs | | | 1,974 | | | 1,695 | | | Subtotal | | | $ | 7,999 | | | $ | 7,695 | | | | | | | | | Deferred Training Costs | | | 49 | | | 46 | | | Total Project Costs before Contingency | | | $ | 8,048 | | | $ | 7,741 | | | | | | | | | Oglethorpe-Level Contingency | | | 52 | | | — | | | Total Contingency | | | $ | 52 | | | $ | — | | | Totals | | | $ | 8,100 | | | $ | 7,741 | | | | | | | | (1) Construction costs are net of $1.1 billion we received from Toshiba Corporation under a Guarantee Settlement Agreement and $99 million in cost sharing benefits associated with the Global Amendments to the Joint Ownership Agreements. |
Any schedule extension beyond March 2023 and March 2024 for Units No. 3 and No. 4, respectively, is expected to increase our financing costs by approximately $30 million per month for both units and approximately $13 million per month for Unit No. 4.
As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the seventeenth VCM reportareas of more than one year. In addition, pursuantengineering support, commodity installation, system turnovers and related test results and workforce statistics.
Since March 2020, the number of active cases of COVID-19 at the site has fluctuated consistent with the surrounding area and impacted productivity levels and pace of activity completion. As of September 30, 2022, the incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity, substantially all of which occurred during 2020 and 2021, is estimated by Georgia Power to be between $350 million and $438 million and is included in the Joint Ownership Agreements,project budget. Subsequent waves of the required approval of holders of ownership interests inCOVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4 is at least (i) 90%4. On July 29, 2022, Southern Nuclear announced that all Unit No. 3 inspections, tests, analyses, and acceptance criteria documentation had been submitted to the Nuclear Regulatory Commission. On August 3, 2022, the Nuclear Regulatory Commission published its 103(g) finding that the acceptance criteria in the combined license for a changeUnit No. 3 had been met, which allowed for nuclear fuel to be loaded and allows start-up testing to begin. Fuel load for Unit No. 3 was completed on October 17, 2022. Georgia Power has disclosed that it projects an in-service date for Unit No. 3 by the end of the primary construction contractorfirst quarter of 2023. Our current budget reflects our expectation of an in-service date for Unit No. 3 in March 2023. The projected schedule for Unit No. 3 primarily depends on the pace of system and (ii) 67% for material amendmentsarea transitions to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor,operations, including the Bechtel Agreement.
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The effectivenessclosure documentation necessary to support start-up testing, and the progression of start-up, final component, and pre-operational testing, which may be impacted by equipment or other operational failures.
Georgia Power has disclosed that it projects an in-service date for Unit No. 4 by the end of the amendments tofourth quarter 2023. Given the Joint Ownership Agreements related to the Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of April 21, 2006, as amended, is subject to the condition that we obtain the approval of the Rural Utilities Service as required under our loan contract with the Rural Utilities Service.In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimatedremaining work to be approximately $230 million. Ifdone and potential risks associated with completing the projectwork, our current budget anticipates an in-service date for Unit No. 4 that is cancelled, we would seek regulatory accounting treatmentone quarter later, in March 2024. Meeting the projected in-service date for Unit No. 4 primarily depends on Unit No. 3 progress through start-up and testing, overall construction productivity and production levels significantly improving, particularly in electrical installation, including terminations; and appropriate levels of craft laborers, particularly electricians, being added and maintained. As Unit No. 4 progresses through construction and continues to amortize our investment intransition into testing, ongoing and potential future challenges include the Vogtle project over a long-term period which would requirepace and quality of electrical, mechanical, and instrumentation and controls commodities installation; availability of craft and supervisory resources, including the approvaltemporary diversion of our boardsuch resources to support Unit No. 3; the pace of directors,work package closures and we would submitsystem turnovers; and the regulatory accounting treatment requesttimeframe and duration of hot functional and other testing.
Ongoing or future challenges for both units also include management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity; ability to the Rural Utilities Service for its approval.We have a $3.06 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.72 billionattract and retain craft labor, and/or related cost escalation. New challenges also may arise, particularly as of September 30, 2017. Pursuant to the terms of the Loan Guarantee Agreement, no further advances are permitted pending satisfaction of certain conditions, including approval of the Bechtel Agreement and an amendment to the Loan Guarantee Agreement. The timing of satisfaction of these conditions is currently uncertain but likely to be satisfied in 2018. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1.62 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the Loan Guarantee Agreement with the Department of Energy, see Note K of Notes to Unaudited Consolidated Financial Statements and for additional information regarding the financing of Vogtle Units No. 3 and No. 4 see "Financing Activities—Departmentmove into initial testing and start-up, which may result in required engineering changes or remediation related to plant systems, structures or components (some of Energy-Guaranteed Loan." We have also financed an additional $1.4 billionwhich are based on
new technology that only within the capital costs oflast few years began initial operation in the Vogtle units through capital market debt issuances.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 as construction proceeds.arise. Processes are in place that are designed to assureensure 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. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending beforeOn March 25, 2022, the Nuclear Regulatory Commission.Commission completed a follow up inspection related to the November 2021 final significance report on its special inspection to review the root cause of additional construction remediation work identified in 2021 and Southern Nuclear’s corresponding corrective action plans. The Nuclear Regulatory Commission closed the findings identified in November 2021 and returned Unit No. 3 to the Nuclear Regulatory Commission’s baseline inspection program. With the receipt of the Nuclear Regulatory Commission’s 103(g) finding, Unit No. 3 is now under the Nuclear Regulatory Commission’s operating reactor oversight process and must meet applicable technical and operational requirements contained within Unit No. 3’s operating license. Various design and other licensing-based compliance matters, including the timely resolutioncompletion of Inspections, Tests, Analyses,inspections, tests, analyses, and Acceptance Criteriaacceptance criteria documentation and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel for Unit No. 4, may arise, if construction proceeds, which may result in additional license amendmentsamendment requests or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria for Unit No. 4, are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs.As construction continues,costs to the risk remains that challenges with management of contractors, subcontractors and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.
Co-owners.
The ultimate outcome of these matters cannot be determined at this time. See "Risk Factors" in this Form 10-Q Co-Owner Contracts and Other Information
In November 2017, the Co-owners entered into an amendment to their joint ownership agreements for risks related to 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 Guarantee Settlementincreased construction budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring report (VCM 19) in 2018, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction. In September 2018, the Co-owners unanimously voted to continue construction of Vogtle Units No. 3 and No. 4.
In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG’s wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC to mitigate certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner’s option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that: •each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's VCM 19 filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs. •Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and
•Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions such as costs that are a result of a force majeure event, that exceed the EAC in VCM 19 by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest).
If the EAC is revised and exceeds the EAC in VCM 19 by more than $2.1 billion, each of the Co-owners, other than Georgia Power, has a one-time option to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power’s agreement to pay 100% of such Co-owner’s share of construction costs actually incurred in excess of the EAC in VCM 19 plus $2.1 billion. If any Co-owner elects to exercise this tender option, Georgia Power would have the option to cancel the project in lieu of accepting the offer to purchase a portion of the Co-owner’s ownership interest. If Georgia Power does not elect to cancel the project, then Georgia Power must accept the offer, and the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the percentage of the cumulative amount of construction costs paid by such tendering Co-owner as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of the tendering Co-owner in accordance with the second and third bullets above will be treated as payments made by that Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a proportionate reduction of our 30% ownership interest.
The VCM 19 total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. As of December 31, 2021, budget increases since VCM 19 have reached $3.4 billion for all Co-owners. As a result of these increases, we believe that the tender option was triggered at the Co-owner construction budget vote on February 14, 2022 and that Georgia Power’s increased responsibility for certain construction costs as described above commenced in March 2022.
On June 17, 2022, we notified Georgia Power of our election to exercise the tender option and cap our capital costs in exchange for a proportionate reduction of our 30% interest in the two new units. Our decremental ownership interest will be calculated and conveyed to Georgia Power after both Vogtle units are placed in service. Based on the current project budget, our schedule assumptions and our interpretation of the Global Amendments, our project budget is $8.1 billion and we expect to transfer approximately 50 megawatts, out of 660 megawatts, to Georgia Power. Our resulting ownership share will decline from 30% to approximately 28%. By exercising the tender option and based on current assumptions, we estimate that we will avoid incurring approximately $500 million in construction costs associated with the project. However, if the total project budget exceeds the current budget, our ownership share and megawatts would be further reduced. On July 26, 2022, the City of Dalton notified Georgia Power that it had elected to exercise its tender option.
We and Georgia Power do not agree on certain aspects of the tender option, including the dollar amount that triggers our option to tender a portion of our ownership interest to Georgia Power under the tender option or the extent to which costs that are the result of a force majeure event (such as COVID-19) impact the point at which the tender option is triggered. For purposes of determining when our option to tender has been triggered, the Global Amendments do not exclude costs resulting from force majeure events (such as COVID-19) from the calculation of when the EAC in VCM 19 plus $2.1 billion has been reached. We and Georgia Power also do not agree on the dollar amount that triggers Georgia Power’s increased responsibility for certain construction costs as described above, and the extent to which costs that are the result of a force majeure event (such as COVID-19), impact the calculation of the point at which Georgia Power’s increased responsibility for certain construction costs as described above is triggered. The exclusion of costs resulting from a force majeure event (such as COVID-19) in the Global Amendments only applies to Georgia Power’s increased cost responsibility during the time period when construction costs exceed the EAC in the nineteenth VCM report by $800 million to $2.1 billion.
Accordingly, in March 2022, we notified Georgia Power of a billing dispute with regards to both the starting dollar amount and the application of costs resulting from a force majeure event and how such amounts impact the thresholds and timing of the cost-sharing and tender option provisions. On June 18, 2022, after completing the dispute resolution procedures set forth in the Ownership Participation Agreement for the additional Vogtle units, we and "Item 1A—RISK FACTORS"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 $8.6 billion, an increase of approximately $500 million, and we would retain our 30% interest in the additional units. On September 26, 2022, the City of Dalton filed a complaint in our 2016lawsuit 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. The schedule extensions announced in February 2022, which reflected a cumulative delay of over a year for each unit from the schedules approved in the seventeenth VCM report, triggered the requirement for the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 to vote to continue construction, and the Co-owners unanimously voted to continue construction.
The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note L of Notes to Unaudited Consolidated Financial Statements.
The ultimate outcome of these matters cannot be determined at this time. See “Item 1A – RISK FACTORS” in our 2021 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.
TableWashington County Power
On October 24, 2022, we entered into an agreement to acquire two generating units at Washington County Power, a four-unit 660 megawatt combustion turbine generation and transmission facility located in Sandersville, Georgia, from Gulf Pacific Power, LLC, an investment fund managed by Harbert Management Corporation. The two acquired units will add approximately 330 megawatts of ContentsEnvironmental natural gas-fired capacity to our generation portfolio. This acquisition is subject to customary closing conditions, including regulatory approvals, and is expected to close in the fourth quarter of 2022.
Federal and state laws and regulations regarding environmental matters affect operations at our facilities. Following are some substantial developments relating to environmental regulations and litigation that have occurred since we filed our Form 10-Q for the quarterly period ended June 30, 2017.On October 10, 2017, the U.S. Environmental Protection Agency (EPA) proposedFor a rule to repeal the Clean Power Plan in its entirety on the basis that the Clean Power Plan exceeds the EPA's authority under the Clean Air Act. Even though some portions of the rule may be in accord with the Clean Air Act, EPA proposes to find that those portions are not severable from the objectionable portions and that the entire Clean Power Plan be repealed. EPA will decide what action, if any, to take in the future with regard to any replacement Clean Power Plan and has stated that it intends to issue an advanced notice of proposed rulemaking in the near future to solicit information on alternate systems to reduce greenhouse gas emissions consistent with its authority under the Clean Air Act. We cannot predict the outcome of this current proposal or any litigation that might be brought challenging any resulting final rule, nor can we predict the outcome of the litigation currently pending on the existing Clean Power Plan.
In September 2017, EPA postponed certain compliance dates for its November 2015 rule for the effluent limitations guidelines and standards for the steam electric power generating (ELG Rule) for two years. Plants Scherer and Wansley are regulated under this rule. EPA has stated that it intends to conduct a rulemaking to potentially revise the more stringent best available technology economically achievable effluent limitations and pretreatment standards for existing sources for flue gas desulfurization wastewater and bottom ash transport water established in the ELG Rule; however, it does not intend to revise the ELG Rule for fly ash transport, flue gas mercury control wastewater or other requirements. We cannot predict the outcome of any actions EPA may take to revise the ELG Rule, or any litigation that might be brought challenging any final rule.
We continue to evaluate all EPA actions regarding reviews and reconsiderations of final rules and processing of proposed rules and cannot predict the outcome of these rulemakings, any related state rulemakings or any related litigation, including litigation that might be brought to challenge the issuance of replacement or new final rules. It is unknown what impact potential rule changes will have on our and our members' operations. Continued uncertainty related to the status of current and future environmental regulations may make long-term planning decisions more difficult.
For further discussion regarding potential effects on our business from environmental regulations, including potential capital requirements, see "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—
Capital Requirements—Capital Expenditures" in our 20162021 Form 10-K10-K. On June 30, 2022, the Supreme Court of the United States issued an opinion that limits the EPA's authority to regulate greenhouse gas emissions under the Clean Air Act. The Court held that the Clean Air Act does not authorize the EPA to regulate the electric industry in a manner as broad as the generation shifting approach set forth in the Clean Power Plan. The EPA has announced its intent to propose a rule for existing power plants pursuant to the Clean Air Act in early 2023. The ultimate impact of the Court's decision cannot be determined at this time.
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 Plan Wansley based upon the August 2022 retirement date and "Item 2—Management's Discussion And Analysis Of Financial Condition And Results Of Operations—Financial Condition—Capital Requirements and Liquidity and Sourcescreated a regulatory asset to defer a portion of Capital—Environmental Regulations" in our quarterly reports on Form 10-Qthe 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 quarterly periods ended March 31, 2017ash pond at Plant Wansley. The proposal recommended closure by removing the ash from the coal ash pond for several site-specific reasons, including available capacity at an existing on-site landfill, the retirement of Plant Wansley, beneficial use of the coal ash, and June 30, 2017.Liquidity
managing construction and operational risks of the previous close in place design. The Georgia Environmental Protection Department must also approve the change in closure plans. We and Georgia Power are continuing to evaluate the costs associated with the modified closure plan; however, we have received preliminary estimates from Georgia Power. At September 30, 2017,2022, we have recognized an additional $66.7 million in coal ash related asset retirement obligations based upon these preliminary cost estimates. We expect to receive more refined estimates
from Georgia Power regarding closure costs and the timing of expenditures prior to year-end 2022. See Note J of Notes to Unaudited Consolidated Financial Statements for additional information regarding the retirement of Plant Wansley and the associated regulatory asset and see “Item 1 – OUR BUSINESS – REGULATION – Environmental – Coal Combustion Residuals and Effluent Limitations Guidelines” in our 2021 Form 10-K for additional information regarding the closure of the coal ash pond. Liquidity At September 30, 2022, we had $1.07$1.5 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $342$573 million in cash and cash equivalents, and $726$880 million of unused and available committed credit arrangements.
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At September 30, 2017, we had $1.61under our $1.8 billion of committed credit arrangements, in place, the details of which are reflected in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | Committed Credit Facilities | | Authorized
Amount | | Available
September 30, 2022 | | | | Expiration
Date | | (dollars in millions) | | | | | | Unsecured Facilities: | | | | | | | | | Syndicated Line of Credit led by CFC | $ | 1,210 | | | $ | 283 | | | '(1) | | December 2024 | CFC Line of Credit(2) | 110 | | | 110 | | | | | December 2023 | | JPMorgan Chase Line of Credit | 350 | | | 347 | | | '(3) | | October 2024 | | Secured Facilities: | | | | | | | | CFC Term Loan(2) | 250 | | | 140 | | | | | December 2023 |
| | | | | | | | | | | | | | | | | | | Committed Credit Facilities
| | | | | | | | | | | | | | Authorized
Amount | | | Available
October 13, 2017 | | Expiration Date
| | | | | | | | | | | | | | (dollars in millions) | | | Unsecured Facilities: | | | | | | | | | Syndicated Line of Credit led by CFC | | $ | 1,210 | | $ | 442 | (1) | March 2020 | CFC Line of Credit(2) | | | 110 | | | 110 | | December 2018 | JPMorgan Chase Line of Credit | | | 150 | | | 34 | (3) | October 2018 | Secured Facilities: | | |
| | |
| | | CFC Term Loan(2) | | | 250 | | | 140 | (2) | December 2018 | | | | | | | | | | | Total | | $ | 1,610 | | $ | 726 | | | | | | | | | | | | |
- (1)
OfThis facility is dedicated to support outstanding commercial paper and the portion of this facility that was unavailable at October 13, 2017, $632 million was dedicated to supportrepresents outstanding commercial paper and $136 million was related to letters of credit issued to support variable rate demand bonds.
- at September 30, 2022.
(2)Any amounts drawn under the $110 million unsecured line of credit with CFC will reduce the amount that can be drawn under the $250 million secured term loan. Therefore, we reflect $140 million as the amount available under the term loan even though there are no amounts have been borrowedoutstanding under that facility. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.
(3)Of the portionthat was unavailable at October 13, 2017, $114 million related toused for letters of credit issued to support variable rate demand bonds and $2 million relatedprovide performance assurance to third parties.
We have the flexibility to use the $1.2 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit issued to post collateral to third parties. Currently, we are primarily using ourand backing up commercial paper program to provide interim funding for payments related to the construction of Vogtle Units No. 3 and No. 4 prior to receiving advances of long-term funding under the Department of Energy-guaranteed Federal Financing Bank loan. See Note K of Notes to Unaudited Consolidated Financial Statements and "—Department of Energy-Guaranteed Loan" for a discussion of recent amendments that were made to the Loan Guarantee Agreement with the Department of Energy which restricts our ability to request further loan advances pending a determination to continue construction of the additional Vogtle units and satisfaction of related conditions, including an amendment to the Loan Guarantee Agreement. Our last advance under this loan was received in December 2016 and timing regarding our ability to make further advances under this loan is uncertain but likely in 2018. The inability to advance funds under our Department of Energy loan has reduced our available liquidity in 2017. We expect this constraint to be mitigated in the coming months through one or more of several potential options including resumption of advances under the Department of Energy loan, monetization of the Toshiba Guarantee Settlement Agreement, or issuance of taxable bonds.
paper. Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. OurDue to this requirement, any commercial paper programwe issue will reduce the availability under the $1.2 billion syndicated line of credit. Currently, we are issuing commercial paper primarily to provide interim funding for:
•payments related to the construction of Vogtle Units No. 3 and No. 4,
•principal payments due under our Department of Energy-guaranteed loans, which began in February 2020 and which we intend to continue funding with commercial paper until Vogtle Unit No. 4 is placed in service, and
•costs related to the Effingham plant acquisition.
We plan to refinance our commercial paper with long-term debt, either through the issuance of first mortgage bonds, through our loan guaranteed by the Department of Energy, or through financing by the Rural Utilities Service.
Our loan guaranteed by the Department of Energy is our preferred source of long-term financing of eligible costs for Vogtle Units No. 3 and No. 4. See Note L of Notes to Unaudited Consolidated Financial Statements and “—Financing Activities—Department of Energy-Guaranteed Loans” for additional information regarding the Department of Energy-guaranteed loans.
Rural Utilities Service financing is our preferred source of long-term financing for the Effingham acquisition. We have a loan agreement with the Rural Utilities Service for this financing and we anticipate fully advancing this loan before the end of 2022.
We intend to issue first mortgage bonds to provide long-term refinancing of all costs not financed through the Department of Energy or the Rural Utilities Service, including refinancing of the principal payments we are currently sized at $1.0 billion.Underpaying under our Department of Energy-guaranteed loans.
At September 30, 2022, under our unsecured committed lines of credit we havehad the ability to issue letters of credit totaling $760$960 million in the aggregate of which $509and $740.3 million remained available at September 30, 2017. However, amounts related to issuedfor the issuance of letters of credit.
Between projected cash on hand and the credit reduce the amount that would otherwise be availablearrangements currently in place, we believe we have sufficient liquidity to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn undercover normal operations and our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit areinterim financing needs, including interim financing for the purposenew Vogtle units, Department of providing credit enhancement on variable rate demand bonds.Energy principal payments, and the Effingham acquisition, until long-term financing is obtained.
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TwoThree of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2017,2022, the required minimum level was $675$750 million and our actual patronage capital was $923 million.$1.2 billion. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0$14 billion and $4.0$4 billion, respectively. At September 30, 2017,2022, we had $8.1$11.4 billion of secured indebtedness and $756$925 million of unsecured indebtedness outstanding.
Under our power bill prepayment program, members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. At September 30, 2017,2022, we had $512seven members participating in the program and a balance of $93.3 million remaining to be applied against future power bills. At September 30, 2022, we had $73.3 million on deposit in the Rural Utilities Service Cushion of Credit Account, and $67.6 million of cash collateral posted by counterparties to our natural gas hedge program, all of which is classified as a restricted investment. See "—Balance Sheet Analysis as of September 30, 2017—Assets" for more information regarding this account.investment and restricted cash, respectively. First Mortgage Indenture. At September 30, 2017,2022, we had $8.1$11.4 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 20162021 Form 10-K for further discussion of our first mortgage indenture.
Bond Financings. In April 2022, we issued $500 million of taxable first mortgage bonds due in 2047 to repay $493.4 million of commercial paper issued to fund a portion of the cost of constructing Vogtle Units No. 3 and No. 4. In the third quarter of 2022, we repaid $31.0 million of our Series 2017 pollution control revenue bonds prior to their final maturity. The first mortgage bonds and the pollution control revenue bonds are secured under our first mortgage indenture. Rural Utilities Service-Guaranteed Loans. At September 30, 2017,2022, we had twoone approved Rural Utilities Service-guaranteed loans being funded through the Federal Financing Bankloan totaling $630.3 million to fund general and environmental improvements that are in various stages of being drawn down. These two loans totaled $678 million with $501had $284.3 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As of September 30, 2017,2022, we had $2.5 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.Department of Energy-Guaranteed Loan. In 2014, On October 18, 2022, we closed on a second Rural Utilities Service-guaranteed loan withfor $234.7 million to fund a portion of our cost to acquire Effingham, and we anticipate fully advancing this loan before the end of 2022.
Department of Energy-Guaranteed Loans. We have loans from the Federal Financing Bank guaranteed by the Department of Energy that will fund up to the lesserprovide funding for over $4.6 billion of $3.06 billion or 70% of eligible project costs related to the cost to construct our 30% undivided share ofinterest in Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the At September 30, 2022, aggregate Department of Energy.As of September 30, 2017, we had advanced $1.72Energy-guaranteed borrowings totaled $4.3 billion, under this loan and had $1.34 billion remaining to be advanced.including capitalized interest. All of the debt advanced under thisthe loan will beguarantee agreement is secured ratably with all other debt under our first mortgage indenture. AccessWe anticipate making the final advance under these loans in the fourth quarter of 2022 in the amount of $358 million.
In accordance with the promissory notes, we began principal repayments of our Department of Energy-guaranteed loans in February 2020. As of September 30, 2022, we had repaid $280.5 million under these loans. If we fully advance these loans, we expect to repay a total of approximately $486 million in principal on these loans by March 2024. We plan to issue first mortgage bonds to refinance the committed funds under thisprincipal repaid after the in-service date of Vogtle Unit No. 4. For more information regarding the loan requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third-parties related to the Vogtle project to comply with certain laws. Seeguarantee agreement, see Note KL of Notes to Unaudited Consolidated Financial Statements for a discussion of recent amendments that were made to the Loan Guarantee Agreement with the Department of Energy which restrict our ability to request further loan advances pending a determination to continue construction of the additional Vogtle units and satisfaction of related conditions, including an amendment to the Loan Guaranty Agreement. Our last advance under this loan was received in December 2016 and timing regarding our ability to make further advances under this facility is uncertain. Under certain circumstances, including a decision not to continue construction of the Vogtle units, the Department of Energy has discretion to require that we repay all amounts outstanding under the loan over a five-year period.On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.62 billion in additional guaranteed funding under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.
In addition to the Department of Energy loan funding, we have issued $1.4 billion of first mortgage bonds to finance a substantial portion of the Vogtle expansion that will not be funded by the
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Department of Energy. As of September 30, 2017, we had $3.1 billion of long-term funding in place for the $3.9 billion invested in the Vogtle project to-date. We anticipate utilizing capital markets financing for any Vogtle related costs that we are not able to advance under the Department of Energy-guaranteed loans.
Bond Financings
On October 12, 2017, we closed on a $122.6 million direct bank purchase of tax-exempt bonds and used the proceeds to retire commercial paper that was issued in January 2017 in connection with the redemption of our remaining auction rate securities. See Note K of Notes to Unaudited Consolidated Financial Statements for more information regarding this refinancing.
In late 2017 or early 2018, we plan to issue approximately $400 million of tax-exempt pollution control revenue bonds, the proceeds of which will be used to refinance $400 million of existing pollution control bonds that are callable on January 1, 2018 and that have higher interest rates than our other tax-exempt debt. When issued, out payment obligations related to these bonds will be secured ratably with all other debt under our first mortgage indenture.
As of September 30, 2017, we had $980.8 million of outstanding obligations related to tax-exempt private activity bonds related to certain of our pollution control facilities. The Tax Cut and Jobs Act, as proposed by members of the House of Representatives on November 2, 2017, could take away our ability to utilize tax-exempt private activity bonds to finance or refinance qualifying pollution control facilities if issued on or after January 1, 2018 and impact the interest rates on our private activity bonds outstanding prior to January 1, 2018.
Statements. For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition— Financing Activities" in our 20162021 Form 10-K.Credit Rating Risk
The table below sets forth our current ratings from S&P Global Ratings, Moody's Investors Service and Fitch Ratings.
| | | | | | | | | | | | | | Our Ratings
| | S&P
| | Moody's
| | Fitch
| | | | | | | | Long-term ratings:
| | | | | | | Senior secured rating
| | A- | | Baa1 | | A- | Issuer/unsecured rating(1)
| | A- | | Baa2 | | N/R(2) | Rating outlook
| | Negative | | Negative | | Rating Watch Negative | Short-term rating:
| | | | | | | Commercial paper rating
| | A-2 | | P-2 | | F2 | | | | | | | |
(1)We currently have no long-term debt that is unsecured.
(2)N/R indicates no rating assigned for this category.
We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable collateral. Our primary exposure to potential collateral postings is at rating levels of BBB–/Baa3 or below. As of September 30, 2017, our maximum potential collateral requirements were as follows:
At senior secured rating levels:
•a total of approximately $52 million at a senior secured level of BBB–/Baa3,
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At senior unsecured or issuer rating levels:
•a total of approximately $0.3 million at a senior unsecured or issuer level of BBB–/Baa3,
•a total of approximately $58 million at a senior unsecured or issuer rating level of BB+/Ba1 or below.
The Rural Utilities Service Loan Contract contains covenants that, upon a credit rating downgrade below investment grade by two rating agencies, could result in restrictions on issuing debt. Certain of our pollution control bond agreements contain provisions based on the ratings assigned to the bonds (which could be related to either our rating or a bond insurer's rating if the bonds are insured) that, upon a credit rating downgrade below specified levels, could result in increased interest rates. Also, borrowing rates and commitment fees in two of our line of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades.
Given our current level of ratings, our management does not have any reason to expect a downgrade that would result in any material impacts to our business. However, our ratings reflect only the views of the rating agencies and we cannot give any assurance that our ratings will be maintained at current levels for any period of time.
Newly Adopted or Issued Accounting Standards For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Consolidated Financial Statements. Item 3. Quantitative and Qualitative Disclosures About Market Risk There have not been anyno material changes to the market risks from those reporteddisclosed in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" ofin our 20162021 Form 10-K. Item 4. Controls and Procedures As of September 30, 2017,2022, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective. There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended September 30, 20172022 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.
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PART II—OTHER INFORMATION Item 1. Legal Proceedings Except as disclosed under "Item 1—Legal Proceedings"
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 seeking a declaratory judgment that the starting dollar amount is $18.38 billion and that costs related to force majeure events are excluded prior to calculating the cost-sharing and tender provisions and when calculating Georgia Power’s related financial obligations. Based on the current project budget and Georgia Power’s interpretation of the Global Amendments, our project budget would be $8.6 billion, an increase of approximately $500 million, and we would retain our 30% interest in the additional units. On September 26, 2022, the City of Dalton filed a complaint in our quarterly reportlawsuit and joined our claims. On September 29, 2022, Georgia Power and MEAG reached an agreement with respect to their pending litigation.
The ultimate outcome of this litigation cannot be determined at this time.
See “Management’s Discussion and Analysis of Financial Condition and Results of Operation – Capital Requirements and Liquidity and Sources of Capital – Vogtle Units No. 3 and No. 4” for additional information regarding Vogtle Units No. 3 and No. 4. For information about loss contingencies that could have an effect on Form 10-Q for the quarterly period ended June 30, 2017, there have been no material changes from the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 2016 Form 10-K.us, see Note H to Unaudited Consolidated Financial Statements. Item 1A. Risk Factors Except as discussed below, there
There have been no material changes fromto the risk factors disclosed in "Item 1A— RISK FACTORS"Risk Factors" in our 20162021 Form 10-K. Our participation in the development and construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.
We are contractually committed to participating in the construction of two additional nuclear units at Plant Vogtle and have committed significant capital expenditures to this endeavor. The construction of large, complex generating plants involves significant financial risk. Further, no nuclear plants have been constructed in the United States using advanced designs, such as the Westinghouse AP1000 design, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also rely on Georgia Power and Southern Nuclear as our agents for the oversight of the construction of the additional units at Plant Vogtle and do not exercise direct control over the construction process.
Our current project budget for the Vogtle Units, which includes capital costs, allowance for funds used during construction and a contingency amount, is $7.0 billion and the scheduled commercial operation dates are November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Certain events have materially delayed the original commercial operation dates and increased the original project budget. The most significant of these relate to the EPC Contractor's filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code and its subsequent rejection of the fixed price EPC Agreement.
We continue to be subject to construction risks and no longer have the benefit of the "fixed" price EPC Agreement, which means that any cost overruns will be allocated to the Co-owners based on their ownership interest percentage. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:
•performance by the EPC Contractor under the Services Agreement;
•performance by Toshiba under the Guarantee Settlement Agreement;
•performance by Bechtel under the Bechtel Agreement as well as subcontractor and supplier performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission;
•changes in labor costs and productivity;
•liens on the project;
•contract disputes;
•loss of access to intellectual property rights necessary to construct or operate the project;
•shortages and/or inconsistent quality of equipment, materials and labor;
•increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;
•unforeseen engineering or design problems;
•permits, approvals and other regulatory matters;
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•unanticipated increases in the costs of materials;
•changes in project design or scope;
•impacts of new and existing laws and regulations, including environmental laws and regulations;
•erosion of public and policymaker support;
•adverse weather conditions; and
•work stoppages.
Additionally, we do not control the determination as to whether the Vogtle project continues to move forward as continued construction of Vogtle Units No. 3 and No. 4 is subject to approval by the Georgia Public Service Commission. On August 31, 2017, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager in its VCM 17 Report filed with the Georgia Public Service Commission. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission is expected to make a decision on these matters by February 6, 2018.
Further, on November 2, 2017, the Co-owners amended the Joint Ownership Agreements to provide that holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction upon the occurrence of any of those adverse events. As we are a 30% owner in the Vogtle project, we, along with Georgia Power and the Municipal Electricity Authority of Georgia, will need to each determine to move forward with the Vogtle project upon the occurrence of certain adverse events. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.
Following the bankruptcy of the EPC Contractor, the rejection of the EPC Agreement and our comprehensive cost-to-complete assessment, we increased our project budget to $7.0 billion from $5.0 billion. This increase is expected to increase our capital expenditures through 2022 and lead to a corresponding increase in our long-term debt outstanding at completion of the Vogtle units to $11.5 billion from the previously disclosed amount of $10 billion. These increases in capital expenditures and in our long-term debt will continue to constrain our equity ratio and will affect certain of our other financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our credit ratings would increase our borrowing costs and decrease our access to the credit and capital markets.
The long-term project cost will also be impacted by our ability to finance the capital costs at competitive interest rates. We are currently unable to make advances from the remaining $1.4 billion of committed funds under our Loan Guarantee Agreement with the Department of Energy and will not be able to make additional advances until we enter into an amendment to the Loan Guarantee Agreement with the Department of Energy. The timing of further advances under the Loan Guarantee Agreement is uncertain but is likely to occur in 2018. Prolonged inability to access funding pursuant to the Department of Energy Loan Guarantee Agreement may constrain our liquidity and lead us to finance certain expenditures through alternative resources, likely at a higher interest rate. We have received a conditional commitment from the Department of Energy for approximately $1.6 billion of additional loan guarantees; however final approval of these additional amounts cannot be assured. See Note K of Notes to Unaudited Consolidated Financial Statements for additional information about the Loan Guarantee Agreement and related conditions.
The ultimate outcome of these matters cannot be determined at this time.
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Any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the cost to the Co-owners of Vogtle Units No. 3 and No. 4, and therefore on our financial condition and results of operations.
On June 9, 2017, Georgia Power and the other Co-owners and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the $3.68 billion amount of its Guarantee Obligations, of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them over as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising remedies in respect of the Toshiba Guarantee, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.
On November 9, 2017, Toshiba released its financial results for the second quarter of fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of September 30, 2017. Toshiba also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.
In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to Department of Energy consents and related approvals under the Loan Guarantee Agreement and related agreements.
The ultimate outcome of these matters cannot be determined at this time.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds Not Applicable. Item 3. Defaults upon Senior Securities Not Applicable. Item 4. Mine Safety Disclosures Not Applicable. Item 5. Other Information Not Applicable.
Not Applicable.
Item 6. Exhibits
| | | | Number | | Description |
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| 4.1 | | Seventy-Fourth Supplemental Indenture, dated as of October 1, 2017, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2017A (Burke) Note, the Series 2017B (Burke) Note, the Series 2017A (Heard) Note and the Series 2017A (Monroe) Note. | |
Number |
4.2 |
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Seventy-Fifth Supplemental Indenture, dated as of October 18, 2017, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Amendment of the Original Indenture.Description |
4.1 |
4.3 |
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4.2 |
10.1 |
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Agreement regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement and Amendment No. 4 to Plant Vogtle Owners Agreement Authorizing Development, Construction, Licensing and Operation of Additional Generating Units,Eighty-Fourth Supplemental Indenture, dated as of November October 18, 2022 2017,, made by and among Georgia PowerOglethorpe to U.S. Bank Trust Company, Oglethorpe, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, andNational Association, as trustee, relating to the City of Dalton.Series 2022 (FFB AE48) Note, Series 2022 (RUS AE48) Reimbursement Note. |
31.1 |
31.1 |
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31.2 |
31.2 |
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32.1 |
32.1 |
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32.2 |
32.2 |
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101 |
101 |
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XBRL Interactive Data File. | | 104 | | | Cover Page Interactive Data File – (embedded within the Inline XBRL document). |
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. | | | | | | | | | | | | | | | | | |
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| Oglethorpe Power Corporation
(An Electric Membership Corporation) |
| | | | | | | Date: | November 13, 201710, 2022 |
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By: |
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/s/ Michael L. Smith | | | | |
| Michael L. Smith
President and Chief Executive Officer |
| | | | | | | Date: | November 13, 201710, 2022 |
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/s/ Elizabeth B. Higgins | | | | |
| Elizabeth B. Higgins
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
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