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
2021 | | | | | | | | | | | |
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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
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4 | | | Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin For the Three and Nine Months ended September 30, 20172021 and 2016 2020 | | | | | | | | | | 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 | | | | | | | | | | | | | | | | | | |
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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, 20172020 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, the construction of two additional nuclear units at Plant Vogtle;
•the resultsduration and severity of Westinghouse Electric Company LLCthe current coronavirus ("COVID-19") pandemic and WECTEC Global Project Services Inc.'s bankruptcy filingresulting economic disruption and any inability or failure by Toshiba Corporation to perform 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;
•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;
•decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;
•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;
•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 decommissioning trust funds including investment performance and projected decommissioning costs;
•early retirement of one or more 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, such as influenza, 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, 20172021 and December 31, 20162020 |
| | | | | | | | | | | | | (dollars in thousands) | | 2021 | | 2020 | | Assets | | | | | Electric plant: | | | | | In service | $ | 9,790,913 | | | $ | 9,394,112 | | | Right-of-use assets—finance leases | 302,732 | | | 302,732 | | | Less: Accumulated provision for depreciation | (5,397,418) | | | (4,968,294) | | | 4,696,227 | | | 4,728,550 | | | Nuclear fuel, at amortized cost | 365,685 | | | 358,728 | | | Construction work in progress | 6,534,429 | | | 5,783,579 | | | Total electric plant | 11,596,341 | | | 10,870,857 | | | Investments and funds: | | | | | Nuclear decommissioning trust fund | 635,958 | | | 598,181 | | | Investment in associated companies | 73,099 | | | 74,844 | | | Long-term investments | 678,704 | | | 518,065 | | | Restricted investments | 73,400 | | | 306,601 | | | Other | 30,441 | | | 29,189 | | | Total investments and funds | 1,491,602 | | | 1,526,880 | | | Current assets: | | | | | Cash and cash equivalents | 452,943 | | | 405,511 | | | Restricted short-term investments | 246,580 | | | 180,986 | | | Receivables | 205,128 | | | 152,466 | | | Inventories, at average cost | 237,018 | | | 280,289 | | | Prepayments and other current assets | 94,370 | | | 33,839 | | | Total current assets | 1,236,039 | | | 1,053,091 | | | Deferred charges: | | | | | Regulatory assets | 898,117 | | | 731,438 | | | Prepayments to Georgia Power | 34,859 | | | 37,601 | | | Other | 59,208 | | | 20,289 | | | Total deferred charges | 992,184 | | | 789,328 | | | Total assets | $ | 15,316,166 | | | $ | 14,240,156 | |
| | | | | | | | | | | (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.
Table of Contents
| | | Oglethorpe Power Corporation
Consolidated Balance Sheets (Unaudited)
September 30, 20172021 and December 31, 20162020 |
| | | | | | | | | | | | | (dollars in thousands) | | | | | | 2021 | | 2020 | | Equity and Liabilities | | | | | Capitalization: | | | | | Patronage capital and membership fees | $ | 1,120,652 | | | $ | 1,072,642 | | | Long-term debt | 10,330,910 | | | 10,298,385 | | | Obligation under finance leases | 65,207 | | | 68,876 | | | Other | 27,402 | | | 26,861 | | | Total capitalization | 11,544,171 | | | 11,466,764 | | | Current liabilities: | | | | | Long-term debt and finance leases due within one year | 263,010 | | | 208,649 | | | Short-term borrowings | 1,023,374 | | | 383,498 | | | Accounts payable | 159,712 | | | 162,249 | | | Accrued interest | 78,276 | | | 72,434 | | | Member power bill prepayments, current | 26,207 | | | 46,068 | | | Other current liabilities | 82,285 | | | 68,932 | | | Total current liabilities | 1,632,864 | | | 941,830 | | | Deferred credits and other liabilities: | | | | | Asset retirement obligations | 1,214,467 | | | 1,135,983 | | | Member power bill prepayments, non-current | 86,492 | | | 98,113 | | | Regulatory liabilities | 816,229 | | | 566,399 | | | Other | 21,943 | | | 31,067 | | | Total deferred credits and other liabilities | 2,139,131 | | | 1,831,562 | | | Total equity and liabilities | $ | 15,316,166 | | | $ | 14,240,156 | |
| | | | | | | | | | | (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.
Table of Contents
| | | Oglethorpe Power Corporation
Consolidated Statements of Revenues and Expenses (Unaudited)
For the Three and Nine Months Ended September 30, 20172021 and 20162020 |
| | | | | | | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | | | | | Three Months | | Nine Months | | 2021 | | 2020 | | 2021 | | 2020 | | Operating revenues: | | | | | | | | | Sales to members | $ | 437,240 | | | $ | 365,937 | | | $ | 1,171,433 | | | $ | 1,038,218 | | | Sales to non-members | 23,582 | | | 302 | | | 23,847 | | | 639 | | | Total operating revenues | 460,822 | | | 366,239 | | | 1,195,280 | | | 1,038,857 | | | Operating expenses: | | | | | | | | | Fuel | 214,681 | | | 131,925 | | | 436,277 | | | 282,677 | | | Production | 99,321 | | | 94,071 | | | 298,171 | | | 303,705 | | | Depreciation and amortization | 69,758 | | | 61,758 | | | 204,654 | | | 186,370 | | | Purchased power | 16,920 | | | 16,419 | | | 50,706 | | | 49,366 | | | Accretion | 14,117 | | | 14,204 | | | 41,839 | | | 40,830 | | | Total operating expenses | 414,797 | | | 318,377 | | | 1,031,647 | | | 862,948 | | | Operating margin | 46,025 | | | 47,862 | | | 163,633 | | | 175,909 | | | | | | | | | | | Other income: | | | | | | | | | Investment income | 12,299 | | | 11,672 | | | 36,389 | | | 36,210 | | | Other | 2,516 | | | 1,832 | | | 4,964 | | | 5,733 | | | Total other income | 14,815 | | | 13,504 | | | 41,353 | | | 41,943 | | | | | | | | | | | Interest charges: | | | | | | | | | Interest expense | 105,201 | | | 101,600 | | | 312,927 | | | 305,128 | | | Allowance for debt funds used during construction | (56,179) | | | (51,518) | | | (164,628) | | | (153,595) | | | Amortization of debt discount and expense | 2,911 | | | 2,813 | | | 8,677 | | | 8,482 | | | Net interest charges | 51,933 | | | 52,895 | | | 156,976 | | | 160,015 | | | Net margin | $ | 8,907 | | | $ | 8,471 | | | $ | 48,010 | | | $ | 57,837 | |
| | | | | | | | | | | | | | | | | (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.
Table of Contents
| | | Oglethorpe Power Corporation
Consolidated Statements of Comprehensive MarginPatronage Capital and Membership Fees (Unaudited)
For the Three and Nine Months Ended September 30, 20172021 and 20162020 |
| | | | | | | (dollars in
thousands) | | Balance at December 31, 2019 | $ | 1,016,747 | | | Net margin | 23,204 | | | Balance at March 31, 2020 | $ | 1,039,951 | | | Net margin | 26,162 | | | Balance at June 30, 2020 | $ | 1,066,113 | | | Net margin | 8,471 | | | Balance at September 30, 2020 | $ | 1,074,584 | | | 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 | | | | | |
| | | | | | | | | | | | | | | | | (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.
Table of Contents
| | | 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, 20172021 and 20162020 |
| | | | | | | | | | | | | (dollars in thousands) | | 2021 | | 2020 | | Cash flows from operating activities: | | | | | Net margin | $ | 48,010 | | | $ | 57,837 | | | Adjustments to reconcile net margin to net cash provided by operating activities: | | | | | Depreciation and amortization, including nuclear fuel | 297,976 | | | 278,872 | | | Accretion cost | 41,839 | | | 40,830 | | | Amortization of deferred gains | (1,341) | | | (1,341) | | | Allowance for equity funds used during construction | (267) | | | (306) | | | Deferred outage costs | (27,163) | | | (36,502) | | | Gain on sale of investments | (11,665) | | | (14,122) | | | Regulatory deferral of costs associated with nuclear decommissioning | (15,592) | | | (11,482) | | | Other | (639) | | | (2,566) | | | Change in operating assets and liabilities: | | | | | Receivables | (51,283) | | | (22,751) | | | Inventories | 46,686 | | | 3,836 | | | Prepayments and other current assets | (6,199) | | | (30,914) | | | Accounts payable | (4,487) | | | (28,764) | | | Accrued interest | 5,842 | | | 10,483 | | | Accrued taxes | 6,788 | | | 35,004 | | | Other current liabilities | 522 | | | (16,433) | | | Member power bill prepayments | (31,482) | | | (56,975) | | | Rate management program collections | 117,600 | | | 114,006 | | | Total adjustments | 367,135 | | | 260,875 | | | Net cash provided by operating activities | 415,145 | | | 318,712 | | | Cash flows from investing activities: | | | | | Property additions | (891,162) | | | (983,902) | | | Plant acquisition | (233,156) | | | — | | | Activity in nuclear decommissioning trust fund—Purchases | (556,879) | | | (393,369) | | | —Proceeds | 550,956 | | | 387,277 | | | Decrease (increase) in restricted investments | 167,607 | | | (7,282) | | | Activity in other long-term investments—Purchases | (340,877) | | | (285,842) | | | —Proceeds | 184,083 | | | 136,476 | | | Other | 8,139 | | | 9,075 | | | Net cash used in investing activities | (1,111,289) | | | (1,137,567) | | | Cash flows from financing activities: | | | | | Long-term debt proceeds | 517,524 | | | 2,045,685 | | | Long-term debt payments | (440,548) | | | (1,274,196) | | | Increase (decrease) in short-term borrowings, net | 639,876 | | | (16,255) | | | Other | 30,124 | | | (1,123) | | | Net cash provided by financing activities | 746,976 | | | 754,111 | | | Net increase (decrease) in cash, cash equivalents and restricted cash | 50,832 | | | (64,744) | | | Cash, cash equivalents and restricted cash at beginning of period | 405,511 | | | 448,612 | | | Cash, cash equivalents and restricted at end of period | $ | 456,343 | | | $ | 383,868 | | | Supplemental cash flow information: | | | | | Cash paid for— | | | | | Interest (net of amounts capitalized) | $ | 141,206 | | | $ | 139,878 | | | Supplemental disclosure of non-cash investing and financing activities: | | | | | Change in asset retirement obligations | $ | 42,964 | | | $ | 22,086 | | | Accrued property additions at end of period | $ | 71,443 | | | $ | 94,365 | |
| | | | | | | | | | | | | | | (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, 20172021 and 2016.2020. 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, 2016,2020, as filed with the SEC. The results of operations for the three-monththree- and nine-month periods ended September 30, 20172021 are not necessarily indicative of results to be expected for the full year. As noted in our 20162020 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 20162020 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 or comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 20172021 and December 31, 2016.2020. | | | | | | | | | | | | | | | | | | | | | | | | | Fair Value Measurements at Reporting Date Using | | | | Quoted Prices in Active Markets for Identical Assets | | Significant Other Observable Inputs | | Significant Unobservable Inputs | | September 30, 2021 | | (Level 1) | | (Level 2) | | (Level 3) | | (dollars in thousands) | | Nuclear decommissioning trust funds: | | | | | | | | | Domestic equity | $ | 225,255 | | | $ | 225,255 | | | $ | — | | | $ | — | | | International equity trust | 142,018 | | | — | | | 142,018 | | | — | | | Corporate bonds and debt | 78,874 | | | — | | | 78,306 | | | 568 | | | US Treasury securities | 54,212 | | | 54,212 | | | — | | | — | | | Mortgage backed securities | 33,712 | | | — | | | 33,712 | | | — | | | Domestic mutual funds | 74,861 | | | 74,861 | | | — | | | — | | | Municipal bonds | 1,130 | | | — | | | 1,130 | | | — | | | Federal agency securities | 9,792 | | | — | | | 9,792 | | | — | | | Non-US Gov't bonds & private placements | 2,696 | | | — | | | 2,696 | | | — | | | Other | 13,408 | | | 13,408 | | | — | | | — | | | Long-term investments: | | | | | | | | | International equity trust | 35,015 | | | — | | | 35,015 | | | — | | | Corporate bonds and debt | 15,590 | | | — | | | 15,272 | | | 318 | | | US Treasury securities | 13,440 | | | 13,440 | | | — | | | — | | | Mortgage backed securities | 11,582 | | | — | | | 11,582 | | | — | | | Domestic mutual funds | 271,354 | | | 271,354 | | | — | | | — | | | Federal agency securities | 290 | | | — | | | 290 | | | — | | | Treasury STRIPS | 325,398 | | | — | | | 325,398 | | | — | | | Other | 6,035 | | | 6,035 | | | — | | | — | | | Natural gas swaps | 93,930 | | | — | | | 93,930 | | | — | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | 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, 2020 | | (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 | $ | 198,325 | | | $ | 198,325 | | | $ | — | | | $ | — | | International equity trust | | 66,861 | | — | | 66,861 | | International equity trust | 120,645 | | | — | | | 120,645 | | | — | | 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 | 98,129 | | | — | | | 97,788 | | | 341 | | | US Treasury securities | | US Treasury securities | 46,963 | | | 46,963 | | | — | | | — | | | Mortgage backed securities | | Mortgage backed securities | 45,039 | | | — | | | 45,039 | | | — | | | Domestic mutual funds | | Domestic mutual funds | 70,813 | | | 70,813 | | | — | | | — | | Municipal bonds | | 943 | | — | | 943 | | Municipal bonds | 1,362 | | | — | | | 1,362 | | | — | | | Federal agency securities | | Federal agency securities | 6,054 | | | — | | | 6,054 | | | — | | Other | | 4,663 | | 4,663 | | — | | Other | 10,851 | | | 7,720 | | | 3,131 | | | — | | 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 | 31,378 | | | — | | | 31,378 | | | — | | Mutual funds | | 57,932 | | 57,932 | | — | | | | Corporate bonds and debt | | Corporate bonds and debt | 29,870 | | | — | | | 29,661 | | | 209 | | | US Treasury securities | | US Treasury securities | 7,437 | | | 7,437 | | | — | | | — | | | Mortgage backed securities | | Mortgage backed securities | 11,432 | | | — | | | 11,432 | | | — | | | Domestic mutual funds | | Domestic mutual funds | 224,536 | | | 224,536 | | | — | | | — | | | Federal agency securities | | Federal agency securities | 537 | | | — | | | 537 | | | — | | | Treasury STRIPS | | Treasury STRIPS | 209,165 | | | — | | | 209,165 | | | — | | Other | | 305 | | 305 | | — | | Other | 3,710 | | | 3,710 | | | — | | | — | | Natural gas swaps | | (15,090 | ) | | — | | (15,090 | ) | Natural gas swaps | 10,248 | | | — | | | 10,248 | | | — | | | | | | | | | | | | | | | | |
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, 20172021 and December 31, 20162020 were as follows (in thousands):follows: | | | | | | | | | | | | | | | | | | | | | | | | | 2021 | | 2020 | | Carrying
Value | | Fair
Value | | Carrying
Value | | Fair
Value | | (in thousands) | | Long-term debt | $ | 10,700,098 | | | $ | 12,568,831 | | | $ | 10,619,826 | | | $ | 13,161,146 | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 20172021 and December 31, 2020 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)Derivative Instruments. 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 hedgingderivative 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, 20172021, all of the counterparties with transaction amounts outstanding under our hedging 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 hedgecontract 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, 20172021 and December 31, 2016,2020, the estimated fair valuevalues of our natural gas contracts was awere net liabilityassets of approximately $807,000$93,930,000 and a net assetliabilities of $15,090,000,approximately $10,248,000, respectively. As of
At September 30, 2017 and2021, one of our counterparties was required to post credit collateral totaling $3,400,000 under our natural gas swap agreements. At December 31, 2016, neither we nor any2020, none of our counterparties were required to post credit support orcollateral. Such collateral underis classified as restricted cash and included in the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on September 30, 2017 due toPrepayments and other current assets line item within our credit rating being downgraded below investment grade, we would have been required to post collateral or lettersunaudited consolidated balance sheets.
The following table reflects the notional volume activity of our natural gas derivatives as ofat September 30, 20172021 that is expected to settle or mature each year: | | | | | | | Year | Natural Gas Swaps (MMBTUs) (in millions) | | 2021 | 4.4 | | | 2022 | 24.2 | | | 2023 | 23.8 | | | 2024 | 23.2 | | | 2025 | 19.9 | | | 2026 | 12.9 | | | Total | 108.4 | |
| | | | | | | | | | | 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, 20172021 and December 31, 2016.
2020. | | | | | | | | | | | | | | | | Balance Sheet Location | Fair Value | | | 2021 | | 2020 | | | (dollars in thousands) | | Assets: | | | | | | Natural gas swaps | Other current assets | $ | 47,303 | | | $ | 222 | | | Natural gas swaps | Other deferred charges | $ | 46,627 | | | $ | — | | | | | | | | Liabilities: | | | | | | Natural gas swaps | Other current liabilities | $ | — | | | $ | 2,305 | | | Natural gas swaps | Other deferred credits | $ | — | | | $ | 8,165 | |
| | | | | | | | | | | | | | | | | | | | | | | 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, 20172021 and 2016.
2020. | | | | | | | | | | | | | | | | | | | | | | | | | | | | Statement of
Revenues and
Expenses
Location | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | 2021 | | 2020 | | 2021 | | 2020 | | | (dollars in thousands) | | Natural gas swaps gains | Fuel | $ | 15,831 | | | $ | 339 | | | $ | 18,229 | | | $ | 339 | | | Natural gas swaps losses | Fuel | — | | | (8,721) | | | (1,311) | | | (20,314) | | | Total | | $ | 15,831 | | | $ | (8,382) | | | $ | 16,918 | | | $ | (19,975) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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)losses on derivative instruments deferred on the balance sheet at September 30, 20172021 and December 31, 2016. 2020.
| | | | | | | | | | | | | | | | Balance Sheet Location | 2021 | | 2020 | | | (dollars in thousands) | | Natural gas swaps | Regulatory asset | $ | — | | | $ | 10,248 | | | Regulatory liability | 93,930 | | | — | | | Total | | $ | 93,930 | | | $ | 10,248 | |
| | | | | | | | | | | | | | | | | | | | | | | 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 ofat September 30, 20172021 and December 31, 2016.2020. | | | | | | | | | | | | | | | | | | | | | | | | | Gross Unrealized | | (dollars in thousands) | | September 30, 2021 | Cost | | Gains | | Losses | | Fair
Value | | Equity | $ | 300,141 | | | $ | 253,423 | | | $ | (4,727) | | | $ | 548,837 | | | Debt | 743,582 | | | 6,727 | | | (3,928) | | | 746,381 | | | Other | 19,444 | | | — | | | — | | | 19,444 | | | Total | $ | 1,063,167 | | | $ | 260,150 | | | $ | (8,655) | | | $ | 1,314,662 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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, 2020 | Cost | | Gains | | Losses | | Fair
Value | | Equity | $ | 262,564 | | | $ | 219,658 | | | $ | (8,127) | | | $ | 474,095 | | | Debt | 613,271 | | | 18,090 | | | (641) | | | 630,720 | | | Other | 11,431 | | | — | | | — | | | 11,431 | | | Total | $ | 887,266 | | | $ | 237,748 | | | $ | (8,768) | | | $ | 1,116,246 | |
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| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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). The new revenue standard requires that an entity recognize revenue to depict 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 either848): Facilitation of the following transition methods: (i) a full retrospective approach reflecting the applicationEffects 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, the FASB issued an update to Topic 606 deferring 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 adoption 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 included in the scope of Topic 606, we have not fully completed our evaluation of the new revenue standard. 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 our revenues is derived from substantially identical wholesale power contracts that we have with each of our 38 members. We expect the pattern of revenue recognition pursuant to our wholesale power contracts will remain unchangedReference Rate Reform on an annual basis under the new revenue standard. However, we continue to evaluate the effects, if any, of Topic 606 on our interim period revenues as it relates to budget adjustments, which have historically been made during the fourth quarter but may also be made during the year that affect our annual revenue requirement and therefore amounts billed to our members. We also continue to evaluate other revenue streams and the related contracts, as well as monitor issues specific to the power and utilities industry. While we have not fully completed our evaluation of the impact of the new revenue recognition guidance, we currently anticipate utilizing a full retrospective transition upon the adoption 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."Reporting”. The amendments in this update addressapply 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 aspects of recognition, measurement, presentation,criteria are met. The expedients and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginningexceptions provided by the amendments in this update do not apply to contract modifications made and hedging relationships entered into or evaluated after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means31, 2022, except for hedging relationships existing as of a cumulative effect adjustment toDecember 31, 2022, for which an entity has elected certain optional expedients that are retained through the balance sheetend 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.
hedging relationship.
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In February 2016,January 2021, the FASB issued "Leases“Reference Rate Reform (Topic 842)." The new leases standard requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases. Both finance leases and operating leases will result in848): Scope,” to further clarify the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortizationscope of the ROU assetreference rate reform guidance in Topic 848. The amendments in this update refine the scope of Topic 848 to clarify that certain optional expedients and exceptions therein for operating leasescontract modifications and hedge accounting apply to contracts that are affected by the lesseediscounting transition. Specifically, modifications related to reference rate reform would recognize a straight-line total lease expense.not be considered an event that requires reassessment of previous accounting conclusions. The new lease standard does not substantially change lessor accounting. 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 new leases standard isamendments in these updates are effective for us on a modified retrospective approach for annual reporting periods beginning afterall entities as of March 12, 2020 through December 15, 2018, and interim periods therein. Early adoption is permitted.31, 2022. We are currently evaluating the future impact of this standard on our consolidated financial statements. In June 2016,December 2019, the FASB issued "Financial Instruments—Credit Losses“Income Taxes (Topic 326)740): MeasurementSimplifying the Accounting for Income Taxes”, as part of Credit Losses on Financial Instruments."its initiative to reduce complexity in the accounting standards. The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses.standard remove certain exceptions and also clarify and simplify various aspects of accounting for income taxes. The new standard iswas effective for us prospectively for annual reporting periods beginning after December 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, 2017,2020, and interim periods therein. Early adoption iswas 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.which we elected not to do. 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 toon January 1, 2021 did not have a material impact on our consolidated financial statements.
In November 2016,
(F)Revenue Recognition. As an electric membership cooperative, our principal business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.
Pursuant to our contracts, we primarily provide 2 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 FASB issued "Statementconsideration 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 Cash Flows (Topic 230): Restricted Cash (a consensusthese 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. The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the FASB Emerging Issues Task Force)."formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The amendmentsregulatory liabilities are amortized to revenue in this standard requireaccordance with the statement of cash flows explainassociated revenue deferral plan as 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 equivalentsexpenses are recognized. For information regarding regulatory accounting, see Note J. Capacity revenues are recognized by us for standing ready to be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period amounts showndeliver electricity to our customers. Our capacity revenues are based on the statementassociated costs we expect to recover in a given year and are generally recognized and billed to our members in equal monthly installments over the course of cash flows. The newthe 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 the 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 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 adoptionthe primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in an interimany given accounting period. Our restricted cash balancesmember 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, 2021 and 2020, we provided approximately 61% and 57% of our members' energy requirements, respectively. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are nominalrequired under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2021, 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 accordinglygenerally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. At September 30, 2021 and September 30, 2020, we recognized refund liabilities
totaling $16,500,000 and $21,400,000, respectively. Based on our current agreements with non-members, we do not expectrefund any consideration received from non-members. Sales to members for the three and nine months ended September 30, 2021 and 2020 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | (dollars in thousands) | | | | | | | | | | 2021 | | 2020 | | 2021 | | 2020 | | Capacity revenues | $ | 228,048 | | | $ | 222,187 | | | $ | 716,303 | | | $ | 721,836 | | | Energy revenues | 209,192 | | | 143,750 | | | 455,130 | | | 316,382 | | | Total | $ | 437,240 | | | $ | 365,937 | | | $ | 1,171,433 | | | $ | 1,038,218 | | | Member energy requirements supplied | 65 | % | | 60 | % | | 61 | % | | 57 | % | | | | | | | | |
Receivables from contracts with our members at September 30, 2021 and December 31, 2020 were $156,095,000 and $135,462,000, respectively. Sales to non-members during the three and nine months ended September 30, 2021 and 2020 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | (dollars in thousands) | | | | | | | | | | 2021 | | 2020 | | 2021 | | 2020 | | Energy revenues | $ | 23,582 | | | $ | 302 | | | $ | 23,847 | | | $ | 639 | | | | | | | | | |
Receivables from non-member energy sales at September 30, 2021 and December 31, 2020 were $6,562,000 and $0, respectively. Energy revenues to non-members for the three and nine months ended September 30, 2021 were primarily from the sale of the Effingham Energy Facility's (Effingham) output into the wholesale market. See Note O for additional information regarding the Effingham acquisition. There were no capacity revenues to non-members for the three and nine months ended September 30, 2021 and 2020. 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, 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 on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members during the nine months ended September 30, 2021 and 2020 were $11,601,000 and $11,805,000, respectively. The cumulative amount billed since inception of the program totaled $107,544,000. In 2018, we began a rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the nine months ended September 30, 2021 and 2020 were $115,837,000 and $93,390,000, respectively. Funds collected through this program are invested and held until applied to members' bills. 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 cumulative amount billed since inception of the program totaled $330,165,000.
In 2021, we implemented an additional rate management program that allows the Effingham deferring members to pay all or a portion of their share of the regulatory asset balance on a current basis. The cumulative amount billed since inception of the program totaled $191,000. See Note O for additional information regarding the Effingham acquisition. (G)Leases. As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. We classify our 4 Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the three and nine months ended September 30, 2021 and 2020 was insignificant. Finance Leases NaN of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and 1 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 or liability. 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 1 renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of thisthe new leases standard, to have a material impact on our consolidated financial statements.(F)Accumulated Comprehensive Margin. The table below provides detail of the beginningwe combine lease 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
nonlease components. | | | | | | | | | | | | | Classification | September 30, 2021 | | December 31, 2020 | | (dollars in thousands) | | Right-of-Use Assets—Finance leases | | | | | Right-of-use assets | $ | 302,732 | | | $ | 302,732 | | | Less: Accumulated provision for depreciation | (266,288) | | | (262,774) | | | Total finance lease assets | $ | 36,444 | | | $ | 39,958 | | | Lease liabilities—Finance leases | | | | | Obligations under finance leases | $ | 65,207 | | | $ | 68,876 | | | Long-term debt and finance leases due within one year | 7,146 | | | 6,773 | | | Total finance lease liabilities | $ | 72,353 | | | $ | 75,649 | |
| | | | | | | | | | | | | Classification | September 30, 2021 | | December 31, 2020 | | (dollars in thousands) | | Right-of-Use Assets—Operating leases | | | | | Electric plant in service | $ | 2,540 | | | $ | 3,283 | | | Total operating lease assets | $ | 2,540 | | | $ | 3,283 | | | Lease liabilities—Operating leases | | | | | Capitalization—Other | $ | 1,677 | | | $ | 2,388 | | | Other current liabilities | 876 | | | 990 | | | Total operating lease liabilities | $ | 2,553 | | | $ | 3,378 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | Three months ended | | Nine months ended | | Lease Cost | Classification | September 30, 2021 | | September 30, 2020 | | September 30, 2021 | | September 30, 2020 | | | (dollars in thousands) | | Finance lease cost: | | | | | | | | | | Amortization of leased assets | Depreciation and amortization | $ | 1,693 | | | $ | 1,344 | | | $ | 4,726 | | | $ | 4,032 | | | Interest on lease liabilities | Interest expense | 2,045 | | | 2,217 | | | 6,133 | | | 6,651 | | | Operating lease cost: | Inventory(1) & production expense | 270 | | | 286 | | | 809 | | | 1,081 | | | Total leased cost | | $ | 4,008 | | | $ | 3,847 | | | $ | 11,668 | | | $ | 11,764 | |
(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.
| | | | | | | | | | | | | | 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 | | | | | | | |
| | | | | | | | | | | | | September 30, 2021 | | December 31, 2020 | | Lease Term and Discount Rate: | | | | | Weighted-average remaining lease term (in years) | | | | | Finance leases | 7.13 | | 7.86 | | Operating leases | 8.01 | | 7.27 | | Weighted-average discount rate: | | | | | Finance leases | 11.05 | % | | 11.05 | % | | Operating leases | 4.76 | % | | 4.63 | % |
| | | | | | | | | | | | | Nine months ended | | September 30, 2021 | | September 30, 2020 | | (dollars in thousands) | | Other Information: | | | | | Cash paid for amounts included in the measurement of lease liabilities | | | | | Operating cash flows from finance leases | $ | 4,180 | | | $ | 4,516 | | | Operating cash flows from operating leases | $ | 890 | | | $ | 1,301 | | | Financing cash flows from finance leases | $ | 3,295 | | | $ | 2,959 | | | 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 at September 30, 2021 is as follows: | | | | | | | | | | | | | | | | | | | (dollars in thousands) | | Year Ending December 31, | Finance Leases | | Operating Leases | | Total | | 2021 | $ | 7,474 | | | $ | 230 | | | $ | 7,704 | | | 2022 | 14,949 | | | 929 | | | 15,878 | | | 2023 | 14,949 | | | 708 | | | 15,657 | | | 2024 | 14,949 | | | 234 | | | 15,183 | | | 2025 | 14,949 | | | 72 | | | 15,021 | | | Thereafter | 40,582 | | | 1,011 | | | 41,593 | | | Total lease payments | $ | 107,852 | | | $ | 3,184 | | | $ | 111,036 | | | Less: imputed interest | (35,499) | | | (631) | | | (36,130) | | | Present value of lease liabilities | $ | 72,353 | | | $ | 2,553 | | | $ | 74,906 | |
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, 2021 and 2020 was as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended September 30, | | Nine months ended September 30, | | 2021 | | 2020 | | 2021 | | 2020 | | (dollars in thousands) | | Lease income | $ | 1,603 | | | $ | 1,543 | | | $ | 4,806 | | | $ | 4,633 | |
| | | | | | | | | | | | | | 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)
On July 29, 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. 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, a medical monitoring fund, and injunctive relief. (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 earnAs of October 1, 2020, 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 reset annually on October 1 of 5% per annum.each year thereafter. The program no longer allows additional funds to be deposited into the account. At September 30, 20172021 and December 31, 2016,2020, we had restricted investments totaling $511,612,000$319,980,000 and $468,179,000,$487,587,000, respectively, of which $265,180,000$73,400,000 and $221,122,000,$306,601,000, respectively, were classified as long-term. 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, 2021 | | September 30, 2020 | | | (dollars in thousands) | | | | | | | | Cash and cash equivalents | $ | 452,943 | | | $ | 383,868 | | | | Restricted cash included in Prepayments and other current assets | 3,400 | | | — | | | | Total cash, cash equivalents and restricted cash reported in the consolidated statements of cash flows | $ | 456,343 | | | $ | 383,868 | | |
(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 ofat September 30, 20172021 and December 31, 2016.2020. | | | | | | | | | | | | | 2021 | | 2020 | | (dollars in thousands) | | Regulatory Assets: | | | | | Premium and loss on reacquired debt(a) | $ | 34,307 | | | $ | 35,433 | | | Amortization of financing leases(b) | 34,555 | | | 35,328 | | | Outage costs(c) | 36,734 | | | 35,232 | | | Asset retirement obligations—Ashpond and other(k) | 272,923 | | | 242,832 | | | Depreciation expense - other(d) | 37,329 | | | 38,396 | | | Depreciation expense - Plant Wansley(e) | 149,641 | | | — | | | Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f) | 55,702 | | | 55,430 | | | Interest rate options cost(g) | 130,367 | | | 126,813 | | | Deferral of effects on net margin—Smith Energy Facility(h) | 144,161 | | | 148,620 | | | Other regulatory assets(o) | 2,398 | | | 13,354 | | | Total Regulatory Assets | $ | 898,117 | | | $ | 731,438 | | | Regulatory Liabilities: | | | | | Accumulated retirement costs for other obligations(i) | $ | 21,124 | | | $ | 20,054 | | | Deferral of effects on net margin—Hawk Road Energy Facility(h) | 17,407 | | | 17,869 | | | Major maintenance reserve(j) | 61,127 | | | 39,776 | | | Amortization of financing leases(b) | 9,182 | | | 11,356 | | | Deferred debt service adder(k) | 134,833 | | | 123,772 | | | Asset retirement obligations—Nuclear(l) | 142,368 | | | 130,901 | | | Revenue deferral plan(m) | 334,645 | | | 220,111 | | | Natural gas hedges(n) | 93,930 | | | — | | | Other regulatory liabilities(o) | 1,613 | | | 2,560 | | | Total Regulatory Liabilities | $ | 816,229 | | | $ | 566,399 | | | Net Regulatory Assets | $ | 81,888 | | | $ | 165,039 | | | | | |
| | | | | | | | | | | | | | | | | | | | 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 is expected as early as fall of 2022. Amortization will commence upon retirement of Plant Wansley and 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 over the subsequent five-year period. (n)Represents deferral associated with unrealized gains on our natural gas hedges.
(o)The amortization periodperiods for other regulatory assets range up to 3329 years and the amortization periodperiods of other regulatory liabilities range up to 106 years.
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(J)(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 two2 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, 2021, borrowings under the Additional FFB Note totaled $867,000,000. At September 30, 2021, aggregate Department of Energy-guaranteed borrowings, including capitalized interest, totaled $3,880,348,382. 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, 2021, we have repaid $158,313,000 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 of Energy-guaranteed borrowings totaled $1,720,997,000, including capitalized interest.
On July 27, 2017, we and the Department of Energy entered into Amendment No. 3 to the Loan Guarantee Agreement. Under the amended terms of the Loan Guarantee Agreement, no advances
Advances under the Facility will be permitted unless and until such time as Georgia Power, on behalf of the Co-owners (as defined inAdditional FFB 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 toNovember 30, 2023.
Future advances under the conditions described above, future advancesFacility 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, 20172021, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $4,517,000$270,524,000 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. Onplants.
In October 30, 2017,2021, we received an additional $17,582,000$12,508,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.
c)On October 12, 2017, the Development Authority
In August 2021, we redeemed $245,605,000 of Burke County (Georgia), the Development Authority of Heard County (Georgia)Series 2009 and the Development Authority of Monroe County (Georgia) issued, on our behalf, $122,620,000 in aggregate principal amount of tax-exempt2010 pollution control revenue bonds forbonds. d)Lines of Credit: On October 1, 2021, we amended our bilateral credit facility with JPMorgan Chase to extend the purpose of refinancing costs associated with certain of our air or water pollution controlexpiration date to October 2024 and sewage or solid waste disposal facilities. The bonds were directly purchased by a bank andreduce the proceeds were usedcommitment amount from $363,000,000 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 scheduled to mature in 2040 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture.(L)- $350,000,000.
(M)Vogtle Units No. 3 and No. 4 Construction Project. We, Georgia Power, the Municipal Electric Authority of Georgia, 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 two2 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 two2 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 design and engineering remains the responsibility of Westinghouse under the Services Agreement.4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will beis 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,
At September 30, 2021, our total investment for our 30% interest in the Co-owners entered into an amendmentadditional Vogtle units was approximately $6.8 billion. We and some of our members have implemented various rate management programs to their joint ownership agreements forlessen the impact on rates when Vogtle Units No. 3 and No. 4 (as amended,reach commercial operation. 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 Joint Ownership Agreements)areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to providemitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who tested positive for amongCOVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. Since March 2020, the number of active cases of COVID-19 at the site has fluctuated and impacted productivity levels and pace of activity completion. As a result, the project has faced challenges, including, but not limited to, higher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation. In 2021, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit No. 3. As a result of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional testing and other conditions,testing, at the end of the second quarter 2021, Southern Nuclear further extended certain milestone dates. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and the pace of system turnovers and Georgia Power has disclosed that it projects an in-service date for Unit No. 3 in the third quarter of 2022. Our current budget reflects our expectation of an in-service date for Unit No. 3 in September 2022. As a result of productivity challenges, at the end of the second quarter 2021 Southern Nuclear also further extended milestone dates for Unit No. 4. Those productivity challenges continued into the third quarter and, in addition, some
craft and support resources were diverted temporarily to support construction efforts on Unit No. 3. The in-service date for Unit No. 4 primarily depends on overall construction productivity as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 in second quarter 2023. Our current budget anticipates an in-service date for Unit No. 4 in June 2023. During the fourth quarter of 2020, Georgia Power established $375 million of additional Co-owner approval requirements. Pursuantcontingency (of which our 30% share was $112.5 million). At March 31, 2021, Georgia Power assigned approximately $183 million (of which our 30% interest was $55 million) of that construction contingency to the Joint Ownership Agreements,base capital cost forecast for costs primarily associated with the holdersschedule extension for Unit No. 3 to December 2021, construction productivity, support resources and construction remediation work. During the first quarter of at least 90%2021, Georgia Power also established an additional $106 million of construction contingency (of which our 30% share was $32 million). At June 30, 2021, the remaining previously established project-level contingency of approximately $300 million (of which our 30% interest was $90 million) and an additional $746 million (of which our 30% interest was $224 million) was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units No. 3 and No. 4, construction remediation work for Unit No. 3, and construction productivity and support resources for Units No. 3 and No. 4. At June 30, 2021, Georgia Power also established an additional $260 million of construction contingency (of which our 30% interest was $78 million) to replenish the project-level construction contingency. Considering the factors above, during the third quarter 2021, the construction contingency established in the second quarter and an additional $278 million (of which our 30% share was $83 million) was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units No. 3 and No. 4, construction productivity and support resources for Units No. 3 and No. 4, and construction remediation work for Unit No. 3. At September 30, 2021, Georgia Power added $300 million (of which our 30% interest is $90 million) to replenish construction contingency. Georgia Power has stated its expectation to allocate the remainder of this project-level contingency by completion of the project. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated by Georgia Power to be between $350 million and $438 million (of which our 30% interest is $105 million to $131 million) and is included in the project budget. Our budget for our 30% 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) the bankruptcy of Toshiba or, except in the case in which eachour allocation of the Co-owners has assigned its rights under the Guarantee Settlement Agreement toproject-level contingency and a third party, a material breach by Toshibaseparate Oglethorpe-level contingency, is $8.25 billion and is based on commercial operation dates 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 relating to the construction of VogtleSeptember 2022 and June 2023 for Units No. 3 and No. 4, will not be recoveredrespectively. The project-level contingency is separate and in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase inaddition to our Oglethorpe-level contingency. The Oglethorpe-level contingency, which we have carried at various levels since the construction budget contained in the seventeenth VCM report of more than $1 billion or extensionbeginning of the project, provides additional margin to cover potential cost, schedule, containedand financing risks associated with our share of the project which may not be covered by project-level contingencies. As construction progresses, the Oglethorpe-level contingency may continue to fluctuate as it represents the difference between known project-level costs and contingencies and our total budget of $8.25 billion. 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, 2021 for our 30% interest in the seventeenth VCM reportproject.
| | | | | | | | | | | | | | | | | | | (in millions) | | Project Budget | | Actual Costs at September 30, 2021 | | Remaining Project Budget | Construction Costs (1) | $ | 6,140 | | | $ | 5,342 | | | $ | 798 | | | Financing Costs | 1,778 | | | 1,443 | | | 335 | | | Total Costs | $ | 7,918 | | | $ | 6,785 | | | $ | 1,133 | | | | | | | | | Project-Level Contingency | $ | 90 | | | $ | — | | | $ | 90 | | | Oglethorpe-Level Contingency | 242 | | | — | | | 242 | | | | | | | | | Total Contingency | $ | 332 | | | $ | — | | | $ | 332 | | | Totals | $ | 8,250 | | | $ | 6,785 | | | $ | 1,465 | | | | | | | | (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement. |
The Oglethorpe-level contingency in our current budget is expected to the Joint Ownership Agreements, the required approvalbe sufficient to cover a few months of holdersadditional delays beyond our assumed in-service dates of ownership interests in Vogtle UnitsSeptember 2022 and June 2023 for Unit No. 3 and Unit No. 4, isrespectively, such as a three-month delay on Unit No. 4 from June 2023 to September 2023. Any further delays are expected to impact our cost by approximately $55 million per month for both units and approximately $25 million per month for Unit No. 4 only, including financing costs. As construction, including subcontract work, continues and testing and system turnover activities increase, risks remain that ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures or components (some of which are based on new technology that only within the last few years began initial operation in the global nuclear industry at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor,this scale), including the Bechtel Agreement.The effectivenessspent fuel pools, any of which may require additional labor and/or materials; or other issues could arise and further impact the amendments to 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 areprojected schedule and estimated to be approximately $230 million. 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.
cost. 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. AsIn connection with the additional construction remediation work described above, Southern Nuclear reviewed the project’s construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the Nuclear Regulatory Commission began a resultspecial inspection to review the root cause of such compliance processes,this additional construction remediation work and the corresponding corrective action plans. On August 26, 2021, the Nuclear Regulatory Commission made preliminary findings of two apparent violations of Nuclear Regulatory Commission regulations, one of low to moderate safety significance, and the other of greater than very low safety significance. The Nuclear Regulatory Commission also made a finding of very low safety significance related to a non-cited violation of its regulations. The Nuclear Regulatory Commission stated that the apparent nonconformances associated with these findings do not represent an immediate safety concern because Unit No. 3 construction is still underway and issues implicating inspections, tests, analyses, and acceptance criteria must be resolved prior to loading nuclear fuel into the Unit No. 3 reactor. Findings from this or other inspections could require additional remediation and/or further Nuclear Regulatory Commission oversight and may impact the projected in-service dates. In addition, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolutionsubmittal by Southern Nuclear of Inspections, Tests, Analyses,the inspections, tests, analyses, and Acceptance Criteriaacceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, have arisen or may arise, if construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria, are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs.costs to the Co-owners. 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 continues,budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring (VCM) report in 2018, the risk remainsholders 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 that challengesmitigated 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 managementthe Term Sheet, the Joint Ownership Agreements provide that:
•each Co-owner is obligated to pay its proportionate share of contractors, subcontractorsconstruction costs for Vogtle Units No. 3 and vendors, labor productivity, fabrication, delivery, assembly,No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and installationNo. 4 which formed the basis of plant systems, structures,Georgia Power's forecast of $8.4 billion in Georgia Power's nineteenth VCM report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs;
•Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a Force Majeure Event, that exceed the EAC in the nineteenth VCM report 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 components,
•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 the nineteenth VCM report 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 the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option to be exercised between 120 and 180 days following the date the revised construction budget is voted on by the Co-owners 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 remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. In this event, Georgia Power would have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Co-owner. If Georgia Power accepts the offer to purchase a portion of another Co-owner’s ownership interest in Vogtle Units No. 3 and No. 4, the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Co-owner and by Georgia Power as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Co-owner in accordance with the second and third bullets above will be treated as payments made by the applicable 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 portion of our 30% ownership interest. Georgia Power and the other Co-owners do not agree on (i) the starting dollar amount for each Co-owner’s option to tender a portion of its ownership interest to Georgia Power under the freeze provision of the Global Amendments or (ii) the starting dollar amount and extent to which costs that are the result of a Force Majeure Event (such as COVID-19) impact the calculation of the cost-sharing provisions of the Global Amendments. The nineteenth VCM report total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. At September 30, 2021, budget increases since the nineteenth VCM have reached $2.4 billion for all Co-owners. As a result of these increases, we believe that the tender option will be triggered at the next Co-owner construction budget vote scheduled for February 2022 and that Georgia Power’s obligation to contribute dollars to the Co-owners under the cost-sharing provisions will commence as early as the first half of 2022. Georgia Power and the other issues could ariseCo-owners recently clarified the process for the freeze provision to provide for a decision between 120 and may further impact project schedule and cost.180 days after the tender option is triggered which will provide additional time to resolve these matters.
The ultimate outcome of these matters cannot be determined at this time.
(N)Measurement of Credit Losses on Financial Instruments. The financial assets we hold that are subject to the new credit losses standard 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 Acquisition. On July 8, 2021, we acquired Effingham County Power, LLC, which owned the Effingham Energy Facility located near Savannah, Georgia, from Effingham County Power Holdings, LLC, an affiliate of the Carlyle Group, Inc. Effingham consists of a natural gas-fired combined cycle unit with an aggregate summer planning reserve generation capacity of approximately 511 megawatts. Subsequently, we dissolved Effingham County Power, LLC and transferred all of its assets and liabilities to Oglethorpe. The purchase price was $233,156,000 and the acquisition also included other transaction costs of approximately $1,382,000 (consisting primarily of legal and professional services). We accounted for the acquisition as an asset acquisition. We financed the acquisition on an interim basis through the issuance of commercial paper. We submitted a loan application and have received a conditional loan commitment from the Rural Utilities Service for long-term financing of this acquisition. For any amounts not funded through the Rural Utilities Service, we intend to issue first mortgage bonds. We expect that any financing from the Rural Utilities Service or through first mortgage bonds will be secured under our first mortgage indenture.
The following amounts represent the identifiable assets acquired and liabilities assumed in the Effingham acquisition:
| | | | | | | | | | Classification | | | | (dollars in thousands) | | Recognized identifiable assets acquired and liabilities assumed: | | | | Electric plant in service, net | $ | 229,215 | | | | Inventories, at average cost | 3,264 | | | | Other current assets | 3,167 | | | | Other current liabilities | (2,490) | | | | Total identifiable net assets | $ | 233,156 | | |
Some of our members elected to take service (scheduling members) at the date of acquisition and some members have elected to defer (deferring members) their share of output until on or before January 2026. Prior to the deferring members’ use of Effingham, their share of output is being sold into the wholesale market. Revenues and costs of output taken by scheduling members are being recognized in the current period. Residual net results of operations from Effingham, including related interest costs, are being deferred as a regulatory asset. This regulatory asset will be amortized over the then remaining life of the plant, estimated to be 22 years at January 2026. If a deferring member elects to take service before January 2026, amortization of the regulatory asset will begin upon taking service.
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. Response to COVID-19 To date, we have successfully navigated the challenges presented by the COVID-19 pandemic and are proud of our associates’ response. As an electric utility, we are deemed part of the nation's critical infrastructure and continued operating during the pandemic to provide electricity to our members and the populations they serve. In June 2021, we completed the reopening of our corporate offices with new safety protocols intended to reduce the risk of transmission of COVID-19. We continue to keep in contact with state and federal regulators to ensure the safety of our associates and reliability of our generation facilities. The ultimate impact of the pandemic on us and our members remains subject to many factors, including the remaining duration and severity of the COVID-19 pandemic and the resulting economic conditions. Results of Operations For the Three and Nine Months Ended September 30, 2021 and 2020 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, 20172021 were $20.8$8.9 million and $63.7$48.0 million compared to $18.6$8.5 million and $62.5$57.8 million for the same periods of 2016.2020. Through September 30, 2017,2021, we collected approximately 123%83% of our targeted net margin of $51.7$57.8 million for the year ending December 31, 2017.2021. 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 2021 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 $16.5 million and $21.4 million at September 30, 2021 and September 30, 2020, 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 20162020 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.
Sales to Members.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.
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The components of member revenues for the three-month and nine-month periods ended September 30, 20172021 and 20162020 were as follows:
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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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September 30, | | Nine Months Ended
September 30, | | | | (dollars in thousands) | | | | (dollars in thousands) | | | | 2021 | | 2020 | | % Change | | 2021 | | 2020 | | % Change | | Capacity revenues | $ | 228,048 | | | $ | 222,187 | | | 2.6 | % | | $ | 716,303 | | | $721,836 | | (0.8)% | | Energy revenues | 209,192 | | | 143,750 | | | 45.5 | % | | 455,130 | | | 316,382 | | 43.9% | | Total | $ | 437,240 | | | $ | 365,937 | | | 19.5 | % | | $ | 1,171,433 | | | $1,038,218 | | 12.8% | | MWh Sales to members | 7,566,980 | | | 7,147,341 | | | 5.9 | % | | 18,727,189 | | | 17,028,641 | | 10.0% | | Cents/kWh | 5.78 | | | 5.12 | | | 12.9 | % | | 6.26 | | | 6.10 | | 2.6% | | Member energy requirements supplied | 65 | % | | 60 | % | | 8.3 | % | | 61 | % | | 57 | % | | 7.0 | % |
Capacity
Energy revenues from members increased for the three-month and nine-month periods ended September 30, 2017 reflect a $5.0 million reduction in revenue requirements for the September 2017 budget adjustment approved by the board of directors discussed above.Energy revenues from members decreased for the three-month and nine-month periods ended September 30, 20172021 compared to the same periods in 20162020 primarily due to a decreasethe recovery of fuel costs. The increase in fuel costs which was largely a result of a decreasemegawatt-hours sold to members also contributed to the increase in generation for member sales in 2017.energy revenues. 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 to non-members were primarily due from the sale of Contents
the Effingham deferring members' output into the wholesale market. See Note O of Notes to Unaudited Consolidated Financial Statements for additional information regarding the Effingham acquisition. There were no capacity revenues to non-members for the three and nine months ended September 30, 2021 and 2020.Sales to non-members during the three and nine months ended September 30, 2021 and 2020 were as follows: | | | | | | | | | | | | | | | | | | | | | | | | | Three Months Ended
September 30, | | Nine Months Ended
September 30, | | | (dollars in thousands) | | | | | | | | | | | 2021 | | 2020 | | 2021 | 2020 | | | Energy revenues | $ | 23,582 | | | $ | 302 | | | $ | 23,847 | | $ | 639 | | | | | | | | | | |
Operating ExpensesExp enses 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 | 2021 | | 2020 | | % Change | | 2021 | | 2020 | | % Change | | 2021 | | 2020 | | % Change | | Coal | $ | 50,384 | | | $ | 29,852 | | | 68.8% | | 1,535,053 | | | 884,482 | | | 73.6% | | 3.28 | | | 3.38 | | | (3.0)% | | Nuclear | 18,849 | | | 19,258 | | | (2.1)% | | 2,434,355 | | | 2,459,582 | | | (1.0)% | | 0.77 | | | 0.78 | | | (1.3)% | | Gas: | | | | | | | | | | | | | | | | | | | Combined Cycle | 121,220 | | | 57,752 | | | 109.9% | | 3,885,404 | | | 3,192,130 | | | 21.7% | | 3.12 | | | 1.81 | | | 72.4% | | Combustion Turbine | 24,228 | | | 25,063 | | | (3.3)% | | 489,436 | | | 807,183 | | | (39.4)% | | 4.95 | | | 3.10 | | | 59.7% | | $ | 214,681 | | | $ | 131,925 | | | 62.7% | | 8,344,248 | | | 7,343,377 | | | 13.6% | | 2.57 | | | 1.80 | | | 42.8% | | | | | | | | | | | | | | | | | | |
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September 30, | | | 2017 vs. | | | Three Months Ended
September 30, | | | 2017 vs. | | | Three Months Ended
September 30, | | | 2017 vs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel Source | | | 2017 | | | 2016 | | | 2016
% Change | | | 2017 | | | 2016 | | | 2016
% Change | | | 2017 | | | 2016 | | | 2016
% Change
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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%) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | 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 | 2021 | | 2020 | | % Change | | 2021 | | 2020 | | % Change | | 2021 | | 2020 | | % Change | | Coal | $ | 86,061 | | | $ | 34,767 | | | 147.5% | | 2,559,235 | | | 982,095 | | | 160.6% | | 3.36 | | | 3.54 | | | (5.1)% | | Nuclear | 57,853 | | | 55,784 | | | 3.7% | | 7,529,053 | | | 7,165,407 | | | 5.1% | | 0.77 | | | 0.78 | | | (1.3)% | | Gas: | | | | | | | | | | | | | | | | | | | Combined Cycle | 252,472 | | | 153,934 | | | 64.0% | | 8,876,229 | | | 8,071,682 | | | 10.0% | | 2.84 | | | 1.91 | | | 48.7% | | Combustion Turbine | 39,891 | | | 38,191 | | | 4.5% | | 873,175 | | | 1,261,013 | | | (30.8)% | | 4.57 | | | 3.03 | | | 50.8% | | $ | 436,277 | | | $ | 282,676 | | | 54.3% | | 19,837,692 | | | 17,480,197 | | | 13.5% | | 2.20 | | | 1.62 | | | 35.8% |
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September 30, | | | 2017 vs. | | | Nine Months Ended
September 30, | | | 2017 vs. | | | Nine Months Ended
September 30, | | | 2017 vs.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Fuel Source | | | 2017 | | | 2016 | | | 2016
% Change | | | 2017 | | | 2016 | | | 2016
% Change | | | 2017 | | | 2016 | | | 2016
% 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, 20172021 compared to the same periods of 2016 primarily due to a decrease in generation2020 as a result of moderate temperatures. In addition,an increase in the average cost of fuel as well as an increase in generation. The increase in average fuel cost was primarily due to higher average natural gas prices in 2021 as prices have increased due to supply and demand pressures. Coal-fired generation increased primarily as a result of the higher average natural gas prices, which caused generation from the coal-fired units to be more economical. The overall increase in generation for the three-month and nine-month periods ended September 30, 2021 compared to the same periods in 2020 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. Production Production costs can vary due to the number and extent of maintenance outages in a given year. Production costs decreased slightly for the nine-month period ended September 30, 20172021 as compared to the same period of 2016 was somewhat affected by2020 primarily as a result of lower fixed major maintenance outage costs at our combined cycle plants. Largely offsetting this decrease were higher fixed major maintenance outage costs at our combustion turbine plants and higher fixed operational costs at our coal-fired and nuclear plants. Production costs increased natural gas pricesslightly for the three-month period ended September 30, 2021 as compared to the same period of 2020 primarily as a result of higher fixed operational costs at our combined cycle and planned maintenance outages during 2017.combustion turbine plants. Interest Charges Net interest charges decreased slightly for the three-month and nine-month periods ended September 30, 2021 as compared to the same periods of 2020 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, 2021 Balance Sheet Analysis as of September 30, 2017
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AssetsAssets
Cash used for property additions for the nine-month period ended September 30, 20172021 totaled $737.1 million.$1.1 billion. Of this amount, approximately $518.5$744.0 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4, $47.7$233.2 million for the Effingham acquisition and $59.4 million was for nuclear fuel purchases andpurchases. The remainder was for expenditures forrelated to normal additions and replacements to our existing generation facilities. Nuclear decommissioning trust fund investments increased $37.8 million for the nine-month period ended September 30, 2021 due to a $21.8 million increase in the fair value of the investments and $16.0 million in investment earnings. Long-term investments increased $160.6 million for the nine-month period ended September 30, 2021 primarily due to purchases under one of our member rate management programs. Funds collected through this rate management program are invested and held until applied to members' bills. At September 30, 2021, total amounts invested under this program, including earnings, during 2021 were $119.1 million. In addition, funds invested, including earnings, during 2021 in our internal nuclear decommissioning fund, coal ash remediation funds and major maintenance reserve funds were $40.9 million. See Note F of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs. Restricted investments consist of 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 these investments for future Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisions regarding whendebt service payments. The program no longer allows additional funds to applybe deposited into the funds are guided byaccount. During the interest rate environment and our anticipated liquidity needs.nine-month period ended September 30,
2021, we utilized $180.6 million for debt service payments and LiabilitiesLong-term debtexpect to utilize the remainder of the balance through 2023. For additional information regarding restricted investments, see Note I of Notes to Unaudited Consolidated Financial Statements.
Receivables increased $98.5$52.7 million during the nine-month period ended September 30, 2017 primarily2021 largely due to the classificationa $27.2 million increase in receivables from members and non-members as a result of $122.6increased sales, a $13.1 million of commercial paper as long-term debt. In October 2017, $122.6receivable related to natural gas purchases and an $8.9 million of tax-exempt bonds was issued to refund the commercial paper on a long-term basis. For information regarding the refunding of commercial paperincrease in receivables from associated organizations for operations and the issuance of tax-exempt bonds, see Note K.Long-term debt and capital leases due within one yearmanagement services.
Inventories decreased $162.0$43.3 million during the nine-month period ended September 30, 2017. The decrease was2021 primarily due to increased generation at our coal-fired plants and the associated increase in coal burn.
Prepayments and other current assets increased $60.5 million during the nine-month period ended September 30, 2021 primarily due to a $47.1 million increase in fair value at September 30, 2021 of our natural gas hedges and a $15.4 million increase in prepaid major maintenance outage costs.
Regulatory assets increased $166.7 million largely as a result of a $149.6 million increase in the deferral of accelerated depreciation associated with the early retirement of Plant Wansley, which is expected as early as fall of 2022. The increase in our regulatory assets was also attributable to the $30.3 million increase in the deferral associated with our coal ash pond asset retirement obligations. These increases were partially offset by a $10.2 million decrease in unrealized losses on our natural gas hedges, which were in an unrealized gain position at September 30, 2021.
Other deferred charges increased $38.9 million during the nine-month period ended September 30, 2021 primarily due to a $46.6 million increase in fair value at September 30, 2021 of our natural gas hedges. Equity and Liabilities Long-term debt and long-term debt and finance leases due within one year increased $86.9 million primarily as a result of a $247.0 million advance under the Department of Energy loan guarantee and $270.5 million in advances under the Rural Utilities Service-guaranteed Federal Financing Bank loan. Offsetting this increase was $440.6 million in debt service payments, including the redemption of $122.6$245.6 million of variable rateSeries 2009 and 2010 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 and the Effingham acquisition, increased $529.8$639.9 million during the nine-month period ended September 30, 2017.Accounts payable2021. During this period, total short-term borrowings were $1.1 billion and repayments totaled $427.5 million.
Regulatory liabilities increased $87.4$249.8 million for the nine-month period ended September 30, 20172021 primarily asdue to a result of a $104.7$114.5 million increase in the payable to Georgia Power Company for operation and maintenance costs for our co-owned plants and capital costsdeferral plan associated with Vogtle Units No. 3one of our member rate management programs. In addition, there was a $93.9 million increase associated with unrealized gains on our natural gas hedges and No. 4. Offsetting thea $21.4 million increase in collections for future major maintenance outages. Additionally, there was $17.2an $11.5 million increase associated with deferred nuclear asset retirement obligations that was primarily driven by an increase in credits appliedunrealized gains associated with our nuclear decommissioning investments. See Note F of Notes to our members' bills in the first quarter of 2017,Unaudited Consolidated Financial Statements for a board approved reduction in 2016 revenue requirements as a result of margins in excessdiscussion of our 2016 target.The current portion of member power bill prepayments decreased $133.2rate management programs.
Asset retirement obligations increased $78.5 million for the nine-month period ended September 30, 20172021 primarily due to the applicationchange in cash flow estimates of credits against the power bills$38.9 million related to coal ash pond decommissioning and $41.8 million in accretion expense. Capital Requirements and Liquidity and Sources of members that participate in the power bill prepayment program. The long-term portion of member power bill prepayments increased $154.1 million for the nine-month period ended September 30, 2017 due to member contributions to the program made during the third quarter of 2017. For additional information on the member power bill prepayment program, see Note J of Notes to Unaudited Consolidated Financial Statements.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, 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
At September 30, 2021, our total investment for itselfour 30% interest in the additional Vogtle units was approximately $6.8 billion. We and as agent forsome of our members have implemented various rate management programs to lessen the Co-owners, entered into an Engineering, Procurementimpact on rates when Vogtle Units No. 3 and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the EPC Contractor). Stone & Webster was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC). Pursuant to the EPC Agreement, the EPC Contractor 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.No. 4 reach commercial operation.
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 EPC Agreement,areas of engineering support, commodity installation, system turnovers and related test results and workforce statistics. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the Co-owners agreedrisk of transmission of COVID-19 at the construction site, including worker distancing measures; isolating individuals who tested positive for COVID-19, showed symptoms consistent with COVID-19, were being tested for COVID-19, or were in close contact with such persons; requiring self-quarantine; and adopting additional precautionary measures. Since March 2020, the number of active cases of COVID-19 at the site has fluctuated and impacted productivity levels and pace of activity completion. As a result, the project has faced challenges, including, but not limited to, payhigher than expected absenteeism; overall construction and subcontractor labor productivity; system turnover and testing activities; and electrical equipment and commodity installation.
In 2021, Southern Nuclear has been performing additional construction remediation work necessary to ensure quality and design standards are met as system turnovers are completed to support hot functional testing, which was completed in July 2021, and fuel load for Unit No. 3. As a purchase price subjectresult of challenges including, but not limited to, construction productivity, construction remediation work, the pace of system turnovers, spent fuel pool repairs, and the timeframe and duration for hot functional testing and other testing, at the end of the second quarter 2021, Southern Nuclear further extended certain price escalationsmilestone dates. Through the third quarter 2021, the project continued to face challenges including, but not limited to, construction productivity, construction remediation work, and adjustments.the pace of system turnovers and Georgia Power has disclosed that it projects an in-service date for Unit No. 3 in the third quarter of 2022. Our current budget reflects our expectation of an in-service date for Unit No. 3 in September 2022. As a result of productivity challenges, at the end of the second quarter 2021 Southern Nuclear also further extended milestone dates for Unit No. 4. Those productivity challenges continued into the third quarter and, in addition, some craft and support resources were diverted temporarily to support construction efforts on Unit No. 3. The EPC Agreement also providedin-service date for liquidated damages uponUnit No. 4 primarily depends on overall construction productivity as well as appropriate levels of craft laborers, particularly electrical and pipefitter craft labor, being added and maintained. Georgia Power has disclosed that it projects an in-service date for Unit No. 4 in second quarter 2023. Our current budget anticipates an in-service date for Unit No. 4 in June 2023. During the EPC Contractor's failurefourth quarter of 2020, Georgia Power established $375 million of additional contingency (of which our 30% share was $112.5 million). At March 31, 2021, Georgia Power assigned approximately $183 million (of which our 30% interest was $55 million) of that construction contingency to fulfillthe base capital cost forecast for costs primarily associated with the schedule extension for Unit No. 3 to December 2021, construction productivity, support resources and certain performance guarantees, each subjectconstruction remediation work. During the first quarter of 2021, Georgia Power also established an additional $106 million of construction contingency (of which our 30% share was $32 million). At June 30, 2021, the remaining previously established project-level contingency of approximately $300 million (of which our 30% interest was $90 million) and an additional $746 million (of which our 30% interest was $224 million) was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units No. 3 and No. 4, construction remediation work for Unit No. 3, and construction productivity and support resources for Units No. 3 and No. 4. At June 30, 2021, Georgia Power also established an aggregate capadditional $260 million of 10%construction contingency (of which our 30% interest was $78 million) to replenish the project-level construction contingency. Considering the factors above, during the third quarter 2021, the construction contingency established in the second quarter and an additional $278 million (of which our 30% share was $83 million) was assigned to the base capital cost forecast for costs primarily associated with the schedule extensions for Units No. 3 and No. 4, construction productivity and support resources for Units No. 3 and No. 4, and construction remediation work for Unit No. 3. At September 30, 2021, Georgia Power added $300 million (of which our 30% interest is $90 million) to replenish construction contingency. Georgia Power has stated its expectation to allocate the remainder of this project-level contingency by completion of the contract price, or approximately $920 million.Toshiba Corporation guaranteed certain payment obligationsproject.
In addition, the continuing effects of the EPC Contractor 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 the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020,COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, 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 worksupport activities at Vogtle Units No. 3 and No. 4,4. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated by Georgia Power actingto be between $350 million and $438 million (of which our 30% interest is $105 million to $131 million) and is included in the project budget.
Our budget 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 on 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 onour 30% ownership interest in 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 Contractor entered into a services agreement, which was amended and restated on July 20, 2017 (the Services Agreement), for the EPC Contractor to transition construction management of Vogtle Units No. 3 and No. 4 to Southern Nuclear and to provide ongoing design, engineering, 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) assume 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. The Services Agreement became effective upon approval by the Department of Energy on July 27, 2017 and 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, our allocation of the project-level contingency and a separate Oglethorpe-level contingency, amount. This budget assumes 100% recovery of our $1.1is $8.25 billion share of the Guarantee Obligations from Toshiba. Asand is based on commercial operation dates 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 schedule2022 and budget, the following table provides an updated estimate of our forecasted capital expenditures related to VogtleJune 2023 for Units No. 3 and No. 4, for 2017 through 2019 (dollarsrespectively.
The project-level contingency is separate and in millions). | | | | | | | | | | | | | |
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| | | | | | | | | | | | | | | | | | 2017 | | | 2018 | | | 2019 | | | Total
| | | | | | | | | | | | | | | | | Future Generation | | $ | 645 | | $ | 677 | | $ | 504 | | $ | 1,826 | | | | | | | | | | | | | | | | |
In addition to our Oglethorpe-level contingency. The Oglethorpe-level contingency, which we have carried at various levels since the amounts reflectedbeginning of the project, provides additional margin to cover potential cost, schedule, and financing risks associated with our share of the project which may not be covered by project-level contingencies. As construction progresses, the Oglethorpe-level contingency may continue to fluctuate as it represents the difference between known project-level costs and contingencies and our total budget of $8.25 billion. 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, 2021 for our 30% interest in the table above, we have budgeted approximately $1.9 billionproject. | | | | | | | | | | | | | | | | | | | (in millions) | | Project Budget | | Actual Costs at September 30, 2021 | | Remaining Project Budget | Construction Costs (1) | $ | 6,140 | | | $ | 5,342 | | | $ | 798 | | | Financing Costs | 1,778 | | | 1,443 | | | 335 | | | Total Costs | $ | 7,918 | | | $ | 6,785 | | | $ | 1,133 | | | | | | | | | Project-Level Contingency | $ | 90 | | | $ | — | | | $ | 90 | | | Oglethorpe-Level Contingency | 242 | | | — | | | 242 | | | | | | | | | Total Contingency | $ | 332 | | | $ | — | | | $ | 332 | | | Totals | $ | 8,250 | | | $ | 6,785 | | | $ | 1,465 | | | | | | | | (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement. |
The Oglethorpe-level contingency in our current budget is expected to complete constructionbe sufficient to cover a few months of Vogtle Unitsadditional delays beyond our assumed in-service dates of September 2022 and June 2023 for Unit No. 3 and Unit No. 4, beyond the years shownrespectively, such as a three-month delay on Unit No. 4 from June 2023 to September 2023. Any further delays are expected to impact our cost by approximately $55 million per month for both units and approximately $25 million per month for Unit No. 4 only, including financing costs. As construction, including subcontract work, continues and testing and system turnover activities increase, risks remain that ongoing or future challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the table. These projected capital expenditures assume that Toshiba fully performs its obligations under the Guarantee Settlement Agreementinstallation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor, and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the failureinitial testing and start-up, including any required engineering changes or any remediation related thereto, 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 Analysisplant systems, structures or components (some 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, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4. Facility design 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 adjustmentare based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel undernew technology that only within 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 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 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 interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba or, exceptlast few years began initial operation 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,global nuclear industry at this scale), including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines thatspent fuel pools, any of Georgia Power's costs relating towhich may require additional labor and/or materials; or other issues could arise and further impact the construction of Vogtle Units No. 3projected schedule and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.
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The effectiveness of the amendments to 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 estimated to be approximately $230 million. 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.
We have a $3.06 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.72 billion 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—Department of Energy-Guaranteed Loan." We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances.
cost. 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. AsIn connection with the additional construction remediation work described above, Southern Nuclear reviewed the project’s construction quality programs and, where needed, is implementing improvement plans consistent with these processes. In June 2021, the Nuclear Regulatory Commission began a resultspecial inspection to review the root cause of such compliance processes,this additional construction remediation work and the corresponding corrective action plans. On August 26, 2021, the Nuclear Regulatory Commission made preliminary findings of two apparent violations of Nuclear Regulatory Commission regulations, one of low to moderate safety significance, and the other of greater than very low safety significance. The Nuclear Regulatory Commission also made a finding of very low safety significance related to a non-cited violation of its regulations. The Nuclear Regulatory Commission stated that the apparent nonconformances associated with these findings do not represent an immediate safety concern because Unit No. 3 construction is still underway and issues implicating inspections, tests, analyses, and acceptance criteria must be resolved prior to loading nuclear fuel into the Unit No. 3 reactor. Findings from this or other inspections could require additional remediation and/or further Nuclear Regulatory Commission oversight and may impact the projected in-service dates. In addition, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolutionsubmittal by Southern Nuclear of Inspections, Tests, Analyses,the inspections, tests, analyses, and Acceptance Criteriaacceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, have arisen or may arise, if construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues, including inspections, tests, analyses, and acceptance criteria, are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs.costs to the Co-owners.
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 continues,budget in connection with Georgia Power’s nineteenth Vogtle construction monitoring (VCM) report in 2018, the risk remainsholders 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 that challengesmitigated 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 managementthe Term Sheet, the Joint Ownership Agreements provide that:
•each Co-owner is obligated to pay its proportionate share of contractors, subcontractorsconstruction costs for Vogtle Units No. 3 and vendors, labor productivity, fabrication, delivery, assembly,No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and installationNo. 4 which formed the basis of plant systems, structures,Georgia Power's forecast of $8.4 billion in Georgia Power's nineteenth VCM report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs;
•Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions such as costs that are a result of a Force Majeure Event, that exceed the EAC in the nineteenth VCM report 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 components,
•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 the nineteenth VCM report 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 the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option to be exercised between 120 and 180 days following the date the revised construction budget is voted on by the Co-owners 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 remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. In this event, Georgia Power would have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Co-owner. If Georgia Power accepts the offer to purchase a portion of another Co-owner’s ownership interest in Vogtle Units No. 3 and No. 4, the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Co-owner and by Georgia Power as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Co-owner in accordance with the second and third bullets above will be treated as payments made by the applicable 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 portion of our 30% ownership interest.
Georgia Power and the other Co-owners do not agree on (i) the starting dollar amount for each Co-owner’s option to tender a portion of its ownership interest to Georgia Power under the freeze provision of the Global Amendments or (ii) the starting dollar amount and extent to which costs that are the result of a Force Majeure Event (such as COVID-19) impact the calculation of the cost-sharing provisions of the Global Amendments. The nineteenth VCM report total project cost is $17.1 billion (which excludes non-shareable costs) as reflected in numerous Georgia Public Service Commission filings. At September 30, 2021, budget increases since the nineteenth VCM have reached $2.4 billion for all Co-owners. As a result of these increases, we believe that the tender option will be triggered at the next Co-owner construction budget vote scheduled for February 2022 and that Georgia Power’s obligation to contribute dollars to the Co-owners under the cost-sharing provisions will commence as early as the first half of 2022. Georgia Power and the other issues could ariseCo-owners recently clarified the process for the freeze provision to provide for a decision between 120 and may further impact project schedule and cost.180 days after the tender option is triggered which will provide additional time to resolve these matters.
The ultimate outcome of these matters cannot be determined at this time. See "Risk Factors" in this Form 10-Q for risks related to For additional information regarding Vogtle Units No. 3 and No. 4, see “Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4” in our 2020 Form 10-K. For information regarding our financing of the Guarantee Settlement Agreementadditional Vogtle units, see “Financing Activities—Department of Energy-Guaranteed Loans” and "ItemNote L of Notes to Unaudited Consolidated Financial Statements. See “Item 1A—RISK FACTORS"FACTORS” in our 20162020 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.
Plant Acquisition: Effingham Energy Facility
TableOn July 8, 2021, we acquired Effingham County Power, LLC, which owned the Effingham Energy Facility (Effingham) located near Savannah, Georgia, from Effingham County Power Holdings, LLC, an affiliate of Contentsthe Carlyle Group, Inc. for a purchase price of $233.2 million. Effingham consists of a natural gas-fired combined cycle unit with an aggregate summer planning reserve generation capacity of approximately 511 megawatts. See Note O of Notes to Unaudited Consolidated Financial Statements for additional information about this acquisition. Environmental Regulations 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, 2017,13, 2021, Georgia Power, as permit holder and operating agent, notified the U.S.Georgia Environmental Protection Agency (EPA) proposed a rule to repeal the Clean Power Plan in its entirety on the basisDivision (EPD) 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 accordPlant Scherer would comply 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 the2020 effluent limitations guidelines and standards(ELG) using the Voluntary Incentives Program (VIP). As such, Plant Scherer will have until December 31, 2028, to install control measures to meet the VIP discharge limitations 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 desulfurizationapplicable wastewater and bottom ash transport water established inpollutants. Under the ELG Rule; however, it does not intendrules, Plant Scherer may still switch compliance subcategories to revisecease the combustion of coal by December 31, 2028, or comply with the generally applicable requirements by December 31, 2025. Additionally, EPD also was informed by Georgia Power on October 13, 2021 that Plant Wansley would comply with the ELG Rule for fly ash transport, flue gas mercury control wastewater or other requirements. We cannot predictrule by ceasing the outcomecombustion 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. Itcoal (i.e., retirement), which 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.
consistent with previously announced retirement plans. For furtheradditional 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 20162020 Form 10-K and "Item 2—Management's Discussion And Analysis Of Financial Condition And Results Of Operations—Financial Condition—Capital Requirements and 10-K. Liquidity and Sources of Capital—Environmental Regulations" in our quarterly reports on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017.Liquidity
At September 30, 2017,2021, we had $1.07$1.2 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $342$452.9 million in cash and cash equivalents, and $726$797 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, 2021 | | | | Expiration
Date | | | | | | (dollars in millions) | | | | | | | | | | Unsecured Facilities: | | | | | | | | | | | | | Syndicated Line of Credit led by CFC | $ | 1,210 | | | $ | 187 | | | '(1) | | December 2024 | | | | | CFC Line of Credit(2) | 110 | | | 110 | | | | | December 2023 | | | | | | JPMorgan Chase Line of Credit | 363 | | | 360 | | | '(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, 2021.
(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 and we have received a conditional loan commitment from the Rural Utilities Service for this financing. See Note O of Notes to Unaudited Consolidated Financial Statements for additional information regarding the Effingham acquisition. We intend to issue first mortgage bonds to provide long-term refinancing of the principal payments we are currently sized at $1.0 billion.Underpaying under our Department of Energy-guaranteed loans and for all other costs not financed through the Department of Energy or the Rural Utilities Service.
At September 30, 2021, under our unsecured committed lines of credit we havehad the ability to issue letters of credit totaling $760$973 million in the aggregate of which $509and $657.0 million remained available at September 30, 2017. However, amounts relatedfor the issuance of letters of credit. On October 1, 2021, we amended our bilateral credit facility with JPMorgan Chase to issuedextend the expiration date to October 2024 and reduce the commitment amount from $363 million to $350 million. We are using this credit facility for letters of credit reduceand plan to use it to support the amount that would otherwise be available to draw for working capital needs. Also, dueinterim financing needs related to the requirementEffingham acquisition. Between projected cash on hand and the credit arrangements currently in place, we believe we have sufficient liquidity 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 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, 2017,2021, the required minimum level was $675$750 million and our actual patronage capital was $923 million.$1.1 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, 2017,2021, we had $8.1$10.7 billion of secured indebtedness and $756 million$1.0 billion of unsecured indebtedness outstanding.
At September 30, 2017,2021, we had $512$320.0 million on deposit in the Rural Utilities Service Cushion of Credit Account, 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.
First Mortgage Indenture. At September 30, 2017,2021, we had $8.1$10.7 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 20162020 Form 10-K for further discussion of our first mortgage indenture.
Rural Utilities Service-Guaranteed Loans. At September 30, 2017,2021, 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 $359.8 million remaining to be advanced. When advanced, the debt will be secured under our first mortgage indenture. As ofAt September 30, 2017,2021, we had $2.5$2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.loans that is secured under our first mortgage indenture. Department of Energy-Guaranteed Loan. In 2014, we closed on a loan withLoans. 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 of 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 theAt September 30, 2021, aggregate Department of Energy.As of September 30, 2017, we had advanced $1.72Energy-guaranteed borrowings totaled $3.9 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. Access
In accordance with the promissory notes, we began principal repayments of our Department of Energy-guaranteed loans in February 2020. At September 30, 2021, we had repaid $158.3 million under these loans. If we fully advance these loans, we expect to repay a total of approximately $394 million in principal on these loans by June 2023. We plan to issue first mortgage bonds to refinance the committed funds underprincipal repaid before the in-service date of Vogtle Unit No. 4. Combined, this loan requires us to meet certain conditions related to our business$4.6 billion and the Vogtle$2.3 billion of debt we have raised in the capital markets represent long-term financing for more than 84% of our $8.25 billion project and also requires certain third-parties relatedbudget. We expect to raise long-term financing for the Vogtle project to comply with certain laws. Seeremaining amounts in the capital markets. For more information regarding the loan guarantee 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 20162020 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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•a total of approximately $81 million at a senior secured level of BB+/Ba1 or below, and
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 20162020 Form 10-K. Item 4. Controls and Procedures As of September 30, 2017,2021, 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, 20172021 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" in our quarterly report on Form 10-Q for the quarterly period ended June 30, 2017, there
There have been no material changes fromto the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 20162020 Form 10-K. For information about loss contingencies that could have an effect on 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 20162020 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.
Item 6. Exhibits
| | | | Number | | Description | | | | | |
|---|
| Number | 4.1 | Description | | 4.1 | | | Seventy-FourthEighty-Second Supplemental Indenture, dated as of October 1, 2017,6, 2021, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to Recording the Series 2017A (Burke) Note, the Series 2017B (Burke) Note, the Series 2017A (Heard) Note and the Series 2017A (Monroe) Note.Indenture in Effingham County, GA. |
31.1 |
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. |
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4.3 |
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Amendment, dated October 18, 2017, to Ninth Amended and Restated Loan Contract, dated as of September 2, 2014, between Oglethorpe and the United States of America. |
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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, dated as of November 2, 2017, by and among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton. |
|
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, 201712, 2021 |
|
By: |
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/s/ Michael L. Smith | | | | |
| Michael L. Smith
President and Chief Executive Officer |
| | | | | | | Date: | November 13, 201712, 2021 |
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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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|
