Document and Entity Information
Document and Entity Information | 6 Months Ended |
Jun. 30, 2018shares | |
Document and Entity Information Abstract | |
Entity Registrant Name | OGLETHORPE POWER CORP |
Entity Central Index Key | 788,816 |
Document Type | 10-Q |
Document Period End Date | Jun. 30, 2018 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Current Reporting Status | No |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 0 |
Document Fiscal Year Focus | 2,018 |
Document Fiscal Period Focus | Q2 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Electric plant: | ||
In service | $ 8,976,019 | $ 8,886,407 |
Less: Accumulated provision for depreciation | (4,391,583) | (4,302,332) |
Net in service | 4,584,436 | 4,584,075 |
Nuclear fuel, at amortized cost | 350,425 | 358,562 |
Construction work in progress | 3,369,651 | 2,935,868 |
Total electric plant | 8,304,512 | 7,878,505 |
Investments and funds: | ||
Nuclear decommissioning trust fund | 446,985 | 445,055 |
Investment in associated companies | 75,246 | 74,981 |
Long-term investments | 151,399 | 140,622 |
Restricted investments | 585,111 | 653,585 |
Other | 23,238 | 22,562 |
Total investments and funds | 1,281,979 | 1,336,805 |
Current assets: | ||
Cash and cash equivalents | 524,874 | 397,695 |
Restricted short-term investments | 219,989 | 229,324 |
Receivables | 164,784 | 156,781 |
Inventories, at average cost | 263,759 | 266,219 |
Prepayments and other current assets | 20,217 | 18,884 |
Total current assets | 1,193,623 | 1,068,903 |
Deferred charges: | ||
Regulatory assets | 597,611 | 585,084 |
Prepayments to Georgia Power | 33,532 | 45,575 |
Other | 13,474 | 13,267 |
Total deferred charges | 644,617 | 643,926 |
Total assets | 11,424,731 | 10,928,139 |
Capitalization: | ||
Patronage capital and membership fees | 955,771 | 911,087 |
Long-term debt | 7,779,704 | 7,927,562 |
Obligation under capital lease | 84,534 | 87,192 |
Other | 20,728 | 20,051 |
Total capitalization | 8,840,737 | 8,945,892 |
Current liabilities: | ||
Long-term debt and capital lease due within one year | 554,340 | 216,694 |
Short-term borrowings | 438,021 | 190,626 |
Accounts payable | 192,590 | 212,868 |
Accrued interest | 85,671 | 79,510 |
Member power bill prepayments, current | 113,025 | 6,171 |
Other current liabilities | 51,238 | 55,136 |
Total current liabilities | 1,434,885 | 761,005 |
Deferred credits and other liabilities: | ||
Asset retirement obligations | 749,659 | 734,997 |
Member power bill prepayments, non-current | 109,000 | 203,615 |
Regulatory liabilities | 253,683 | 251,649 |
Other | 36,767 | 30,981 |
Total deferred credits and other liabilities | 1,149,109 | 1,221,242 |
Total equity and liabilities | $ 11,424,731 | $ 10,928,139 |
Consolidated Statements of Reve
Consolidated Statements of Revenues and Expenses - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Operating revenues: | ||||
Total operating revenues | $ 365,921 | $ 361,369 | $ 739,567 | $ 715,539 |
Operating expenses: | ||||
Fuel | 122,144 | 118,723 | 242,591 | 222,638 |
Production | 101,891 | 99,185 | 203,163 | 200,273 |
Depreciation and amortization | 56,841 | 55,977 | 113,629 | 111,840 |
Purchased power | 14,761 | 14,901 | 30,649 | 29,877 |
Accretion | 9,435 | 9,111 | 18,756 | 18,109 |
Total operating expenses | 305,072 | 297,897 | 608,788 | 582,737 |
Operating margin | 60,849 | 63,472 | 130,779 | 132,802 |
Other income: | ||||
Investment income | 14,719 | 14,840 | 28,683 | 29,659 |
Other | 1,643 | 641 | 3,617 | 1,281 |
Total other income | 16,362 | 15,481 | 32,300 | 30,940 |
Interest charges: | ||||
Interest expense | 91,825 | 93,527 | 181,495 | 186,812 |
Allowance for debt funds used during construction | (34,950) | (33,349) | (69,149) | (66,436) |
Amortization of debt discount and expense | 3,051 | 3,099 | 6,049 | 6,236 |
Net interest charges | 59,926 | 63,277 | 118,395 | 126,612 |
Net margin | 17,285 | 15,676 | 44,684 | 37,130 |
Members | ||||
Operating revenues: | ||||
Total operating revenues | 365,811 | 361,323 | 739,212 | 715,467 |
Non-Members | ||||
Operating revenues: | ||||
Total operating revenues | $ 110 | $ 46 | $ 355 | $ 72 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Margin - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Consolidated Statements of Comprehensive Margin | ||||
Net margin | $ 17,285 | $ 15,676 | $ 44,684 | $ 37,130 |
Other comprehensive margin: | ||||
Unrealized gain (loss) on available-for-sale securities | 1 | (38) | ||
Total comprehensive margin | $ 17,285 | $ 15,677 | $ 44,684 | $ 37,092 |
Consolidated Statements of Patr
Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | ||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | |
Increase (Decrease) in Members' Capital | ||||
Balance | $ 911,087 | $ 859,440 | ||
Components of comprehensive margin: | ||||
Net margin | $ 17,285 | $ 15,676 | 44,684 | 37,130 |
Unrealized gain (loss) on available-for-sale securities | 1 | (38) | ||
Balance | 955,771 | 896,532 | 955,771 | 896,532 |
Patronage Capital and Membership Fees | ||||
Increase (Decrease) in Members' Capital | ||||
Balance | 911,087 | 859,810 | ||
Components of comprehensive margin: | ||||
Net margin | 44,684 | 37,130 | ||
Balance | $ 955,771 | 896,940 | $ 955,771 | 896,940 |
Accumulated Other Comprehensive Deficit | ||||
Increase (Decrease) in Members' Capital | ||||
Balance | (370) | |||
Components of comprehensive margin: | ||||
Unrealized gain (loss) on available-for-sale securities | (38) | |||
Balance | $ (408) | $ (408) |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2017 | |
Cash flows from operating activities: | ||
Net margin | $ 44,684 | $ 37,130 |
Adjustments to reconcile net margin to net cash provided by operating activities: | ||
Depreciation and amortization, including nuclear fuel | 184,323 | 185,640 |
Accretion cost | 18,756 | 18,109 |
Amortization of deferred gains | (894) | (894) |
Allowance for equity funds used during construction | (450) | (387) |
Deferred outage costs | (12,411) | (22,194) |
Loss (gain) on sale of investments | 3,152 | (16,352) |
Regulatory deferral of costs associated with nuclear decommissioning | (13,966) | 5,707 |
Other | (2,637) | (4,934) |
Change in operating assets and liabilities: | ||
Receivables | (7,254) | 4,556 |
Inventories | 2,460 | (6,897) |
Prepayments and other current assets | (518) | 361 |
Accounts payable | (25,517) | 27,736 |
Accrued interest | 6,161 | (31,944) |
Accrued taxes | 1,269 | (2,641) |
Other current liabilities | (7,600) | (4,852) |
Member power bill prepayments | 12,239 | (48,831) |
Other | 6,188 | |
Total adjustments | 163,301 | 102,183 |
Net cash provided by operating activities | 207,985 | 139,313 |
Cash flows from investing activities: | ||
Property additions | (561,033) | (474,683) |
Activity in nuclear decommissioning trust fund - Purchases | (262,959) | (235,754) |
Activity in nuclear decommissioning trust fund - Proceeds | 259,092 | 232,376 |
Decrease in restricted investments | 68,474 | 12,147 |
Decrease in restricted short-term investments | 9,335 | 61,889 |
Activity in other long-term investments - Purchases | (102,715) | (39,042) |
Activity in other long-term investments - Proceeds | 90,329 | 25,390 |
Other | 10,473 | (2,225) |
Net cash used in investing activities | (489,004) | (419,902) |
Cash flows from financing activities: | ||
Long-term debt proceeds | 236,200 | 4,517 |
Long-term debt payments | (77,234) | (240,182) |
Increase in short-term borrowings, net | 247,395 | 425,929 |
Other | 1,837 | 10,141 |
Net cash provided by financing activities | 408,198 | 200,405 |
Net increase (decrease) in cash and cash equivalents | 127,179 | (80,184) |
Cash and cash equivalents at beginning of period | 397,695 | 366,290 |
Cash and cash equivalents at end of period | 524,874 | 286,106 |
Cash paid for - | ||
Interest (net of amounts capitalized) | 104,670 | 150,849 |
Supplemental disclosure of non-cash investing and financing activities: | ||
Change in asset retirement obligations | 2,404 | 0 |
Accrued property additions at end of period | 141,338 | 104,799 |
Interest paid-in-kind | $ 29,072 | $ 28,092 |
General
General | 6 Months Ended |
Jun. 30, 2018 | |
General | |
General | (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, the results for the three-month and six-month periods ended June 30, 2018 and 2017. Examples of estimates used include those related to our asset retirement obligations and revenue recognition. Estimates for our asset retirement obligations include items such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates. Estimates for revenue recognition include items 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. Certain prior year amounts have been reclassified to conform with current year presentation. Pursuant to our adoption of Revenue from Contracts with Customers (Topic 606), we adjusted sales to members for the three and six month periods ended June 30, 2017 in our Consolidated Statements of Revenues and Expenses to reflect a $5.8 million refund liability. The refund liability represents the adjustment to our revenue that we assessed as of June 30, 2017, that would have been required to meet our 2017 annual revenue requirement. These consolidated financial statements should be read in conjunction with the financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, as filed with the SEC. The results of operations for the three-month and six-month periods ended June 30, 2018 are not necessarily indicative of results to be expected for the full year. As noted in our 2017 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 2017 Form 10-K. |
Fair Value
Fair Value | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value | |
Fair Value | (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. As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques: 1. Market approach . The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs. 2. Income approach . The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. 3. Cost approach. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using June 30, 2018 Quoted Prices in Significant Other Significant ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ — $ — International equity trust — — Corporate bonds and debt — US Treasury securities — — Mortgage backed securities — — Domestic mutual funds — — Municipal bonds — — Federal agency securities — — Non-US Gov't bonds & private placements — — Other — — Long-term investments: International equity trust — — Corporate bonds and debt — US Treasury securities — — Mortgage backed securities — — Domestic mutual funds — — Federal agency securities — — Treasury STRIPS — — Other — — Natural gas swaps — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, Quoted Prices in Significant Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ — International equity trust — Corporate bonds and debt — US Treasury securities — Mortgage backed securities — Domestic mutual funds — Municipal bonds — Federal agency securities — Other — Long-term investments: International equity trust — Corporate bonds and debt — US Treasury securities — Mortgage backed securities — Domestic mutual funds — Federal agency securities — Other — Natural gas swaps — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The Level 2 investments above in corporate bonds and debt, federal agency mortgage backed securities, and mortgage backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a 3-day redemption notice period. The Level 3 investments above in corporate bonds and debt consist of investments in bank loans which are not exchange traded. Although these securities may be liquid and priced daily, their inputs are not observable. The following table presents the changes in Level 3 assets measured at fair value on a recurring basis during the three and six months ended June 30, 2018. ​ ​ ​ ​ ​ Three Months Ended Corporate bonds and debt ​ ​ ​ ​ ​ (dollars in thousands) Balance at March 31, 2018 $ Transfers to Level 3 Total gains or losses (realized/unrealized): Changes in net assets — ​ ​ ​ ​ ​ Balance at June 30, 2018 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended Corporate bonds and debt ​ ​ ​ ​ ​ (dollars in thousands) Balance at December 31, 2017 $ — Transfers to Level 3 Total gains or losses (realized/unrealized): Changes in net assets — ​ ​ ​ ​ ​ Balance at June 30, 2018 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ None of our assets or liabilities measured at fair value on a recurring basis were categorized as Level 3 at December 31, 2017. The estimated fair values of our long-term debt, including current maturities at June 30, 2018 and December 31, 2017 were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Carrying Fair Carrying Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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). The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of June 30, 2018 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. For cash, cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury. |
Derivative Instruments
Derivative Instruments | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments | |
Derivative Instruments | (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. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions. It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of June 30, 2018, 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 hedge 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. At June 30, 2018 and December 31, 2017, the estimated fair value of our natural gas contracts was a net liability of approximately $11,382,000 and $6,328,000, respectively. As of June 30, 2018 and December 31, 2017, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2018 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $11,382,000 with our counterparties. The following table reflects the notional volume of our natural gas derivatives as of June 30, 2018 that is expected to settle or mature each year: ​ ​ ​ ​ ​ Year Natural Gas Swaps (in millions) ​ ​ ​ ​ ​ 2018 2019 2020 2021 2022 2023 ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​ The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 2017 (dollars in thousands) Assets: Natural gas swaps Other current assets $ $ Liabilities: Natural gas swaps Other current liabilities $ $ Natural gas swaps Other deferred credits $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and six months ended June 30, 2018 and 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of Three months Six months 2018 2017 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Natural Gas Swaps Fuel $ $ $ $ Natural Gas Swaps Fuel ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Natural gas swaps Regulatory asset $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Investments in Debt and Equity
Investments in Debt and Equity Securities | 6 Months Ended |
Jun. 30, 2018 | |
Investments in Debt and Equity Securities | |
Investments in Debt and Equity Securities | (D) Investments in Debt and Equity Securities. Investment securities we hold are carried at market value. Prior to October 1, 2017, unrealized gains and losses of investment securities related to nuclear decommissioning were deferred pursuant to regulated operations accounting, while those for all other investment securities were recorded to accumulated other comprehensive (deficit) margin. During the fourth quarter of 2017, we began applying regulated operations accounting to the unrealized gains and losses for all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. As of June 30, 2018, approximately 66% of these gross unrealized losses had been unrealized for a duration of less than one year. The following tables summarize debt and equity securities as of June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Unrealized ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) June 30, 2018 Cost Gains Losses Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Unrealized ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) December 31, 2017 Cost Gains Losses Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Recently Issued or Adopted Acco
Recently Issued or Adopted Accounting Pronouncements | 6 Months Ended |
Jun. 30, 2018 | |
Recently Issued or Adopted Accounting Pronouncements | |
Recently Issued or Adopted Accounting Pronouncements | (E) Recently Issued or Adopted Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (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. In addition, Topic 606 requires disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers. We adopted the new revenue standard effective January 1, 2018, using the full retrospective method, which required us to restate each prior reporting period presented. The adoption of the new revenue standard did not change the nature, amounts or timing of revenues we recognize within an annual reporting period. The most significant impact of the new revenue standard to us relates to the potential recognition of refund liabilities related to capacity revenues in interim reporting periods. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. For the six months ended June 30, 2018 and 2017, we recognized refund liabilities totaling $5,650,000 and $5,750,000, respectively. Adoption of the new revenue standard had no impact to cash from or used in operating, financing, or investing on our consolidated cash flows statements. In January 2016, the FASB issued "Financial Instruments—Overall (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities." The amendments in this update address certain aspects of recognition, measurement, presentation, and disclosure of financial instruments. The new standard is effective for us for annual reporting periods beginning after December 15, 2017, and interim periods therein. Certain provisions within this update can be adopted early. Certain provisions within this update should be applied by means of a cumulative effect adjustment to the balance sheet of the fiscal year of adoption and certain provisions should be applied prospectively. One of the provisions in this standard requires our equity investments, except those accounted for under the equity method of accounting or those that result in consolidation of our subsidiary, to be measured at fair value with changes in fair value recognized in net income. None of the other provisions in this standard will have any impact to our consolidated financial statements. Effective December 31, 2017, we adopted regulatory accounting treatment with respect to unrealized gains and/or losses on our equity investments. Upon applying regulatory accounting treatment, unrealized gains on our equity investments will be recorded as a regulatory liability and, conversely, unrealized losses on our equity investments will be recorded as a regulatory asset, at the end of each reporting period. As of December 31, 2017, we recorded $618,000 of unrealized losses on our equity investments as a regulatory asset. On January 1, 2018, we adopted the amendments within this standard. The adoption of this standard did not have any impact to our consolidated financial statements due to our regulatory accounting treatment for unrealized gains and/or losses on our equity investments. In February 2016, the FASB issued "Leases (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 in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The new lease standard does not substantially change lessor accounting. The new leases standard is effective for us on a modified retrospective approach for annual reporting periods beginning after December 15, 2018, and interim periods therein. Early adoption is permitted. In January 2018, the FASB issued "Land Easement Practical Expedient for Transition to Topic 842" that allows an entity to not evaluate existing and expired land easements that were not previously accounted for as leases upon adoption of Topic 842. Any land easements entered into prospectively or modified after adoption should be evaluated to assess whether they meet the definition of a lease. In July 2018, the FASB issued "Codification Improvements to Topic 842, Leases" to clarify certain narrow aspects of the guidance in Topic 842. The effective date and transition requirements in this standard are the same as the requirements in Topic 842. We are currently assessing the potential impacts of the amendments in this standard in context of the overall adoption of the new accounting guidance for leases. In addition, we continue to monitor both the FASB's ongoing standard-setting activities that may result in the issuance of additional targeted improvements, as well as potential industry implementation issues. In July 2018, the FASB issued "Leases (Topic 842): Targeted Improvements" to add a new transition method to the new leases standard that allows entities to not apply the new guidance in the comparative periods entities present in their financial statements in the year of adoption. The FASB also provided a practical expedient that gives lessors an option to combine non-lease and associated lease components when certain criteria are met and requires a lessor to account for the combined component in accordance with the new revenue standard if the associated non-lease components are the predominant component. While we have not fully completed our evaluation of the new leases standard, we expect that the adoption of such standard will not have a material impact on our consolidated financial statements. Our lease portfolio consists of our 60% undivided interest in Scherer Unit No. 2, railcars leases for the transportation of coal and various nominal leases. We account for the Scherer Unit No. 2 leases as capital leases and the railcars leases as operating leases under the current lease accounting model. At this time, we believe that the key changes in adopting the new leases standard will be how we account for our operating leases that are currently off-balance sheet. Our evaluation process includes, but is not limited to, reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients available to us. We will adopt the new leases standard on January 1, 2019. In June 2016, the FASB issued "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replace the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new standard is effective for us prospectively for annual reporting periods beginning after December 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 March 2018, the FASB issued "Income Taxes (Topic 740): Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin No. 118." In accordance with the standard, we recognized the provisional tax impacts related to the re-measurement of our deferred income tax assets and liabilities as of the year ended December 31, 2017. As of June 30, 2018, we have not made any additional measurement-period adjustments related to these items. Such adjustments may be necessary in future periods due to, among other things, the significant complexity of the Tax Cuts and Job Act signed into law in December 2017, and anticipated additional regulatory guidance that may be issued by the Internal Revenue Service, changes in analysis, interpretations and assumptions we made and actions we may take as a result of the Act. We are continuing to gather information to assess the application of the Act and expect to complete our analysis with the filing of our 2017 income tax returns during the fourth quarter of 2018. |
Revenue Recognition
Revenue Recognition | 6 Months Ended |
Jun. 30, 2018 | |
Revenue Recognition | |
Revenue Recognition | (F) Revenue Recognition. As an electric membership cooperative, our principle 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 through December 30, 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. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments. Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that reflects the consideration we expect to receive in exchange for those services. Capacity and energy are distinct and we account for them as separate performance obligations. The obligations to provide capacity and energy are satisfied over time as the customer simultaneously receives and consumes the benefit of these services. Both performance obligations are provided directly by us and not through a third party. Each of our members is obligated to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. 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 obligates each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices agreed to by us in the applicable agreement. Margins produced from non-member sales are included in the rate schedule formula and reduce revenue requirements from our members. The standard selling price at which we provide capacity services to our members is determined by our formulary rate on an annual basis. As a result, the consideration we receive for providing capacity services is determined annually. Over the course of a year, our member capacity revenues are relatively stable. Capacity revenues may fluctuate year to year largely due to the recovery of fixed operation and maintenance costs. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as depreciation, interest, fixed operation and maintenance expenses, administrative and general expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan. For information regarding regulatory accounting, see Note I. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, 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 significant financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. The discounts are credited against the participating members' power bills on a monthly basis. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. Application of the prepayments extends through January 2023, with the majority of the balance scheduled to be applied by the end of 2019. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We do not provide all of our members' energy requirements. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2018, our board has approved a targeted margins for interest ratio of 1.14 and for 2017, we achieved a margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine if a refund to our members of excess consideration is likely. If required, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of June 30, 2018 and 2017, we recognized refund liabilities totaling $5,650,000 and $5,750,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members were as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Six Months (dollars in thousands) (dollars in thousands) 2018 2017 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capacity revenues $ $ $ $ Energy revenues ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Sales to non-members during the three and six months ended June 30, 2018 and June 30, 2017 were insignificant. We bill our members for capacity and energy on a monthly basis. Based on the payment terms of the wholesale power contracts and power purchase and sale agreements, we receive payment during the following month in which capacity and energy revenues are billed. Estimated energy charges are billed to members based on the amount of energy supplied during the month and are adjusted when actual costs are available, generally the following month. As payment is due to us within one month of billing, we do not provide significant financing to our customers. The opening and closing balances of receivables from contracts with our customers are as follows: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ June 30, June 30, December 31, December 31, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Receivables from members $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 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. For the three and six months ended June 30, 2018 and June 30, 2017, no impairment losses were recognized on any receivables that arose from contracts with our customers. |
Contingencies and Regulatory Ma
Contingencies and Regulatory Matters | 6 Months Ended |
Jun. 30, 2018 | |
Contingencies and Regulatory Matters | |
Contingencies and Regulatory Matters | (G) 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. As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide. In general, these and other types of environmental requirements have become increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any potential new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs. Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent. |
Restricted Investments
Restricted Investments | 6 Months Ended |
Jun. 30, 2018 | |
Restricted Investments | |
Restricted Investments | (H) Restricted Investments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit earn interest at a rate of 5% per annum. At June 30, 2018 and December 31, 2017, we had restricted investments totaling $805,100,000 and $882,909,000, respectively, of which $585,111,000 and $653,585,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank. |
Regulatory Assets and Liabiliti
Regulatory Assets and Liabilities | 6 Months Ended |
Jun. 30, 2018 | |
Regulatory Assets and Liabilities | |
Regulatory Assets and Liabilities | (I) Regulatory Assets and Liabilities. We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery from our members in future revenues through rates under the wholesale power contracts we have with each of our members. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members. The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ 2018 2017 (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Asset retirement obligations—Ashpond and other (k) Depreciation expense (d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) Interest rate options cost (f) Deferral of effects on net margin—Smith Energy Facility (g) Other regulatory assets (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets $ $ Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ $ Deferral of effects on net margin—Hawk Road Energy Facility (g) Major maintenance reserve (i) Amortization on capital leases (b) Deferred debt service adder (j) Asset retirement obligations—Nuclear (k) Other regulatory liabilities (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ Net Regulatory Assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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 26 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Deferred charges related to Vogtle Units No. 3 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. (f) Deferral of premiums paid to purchase interest rate options to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No.3 and No.4. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (g) 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. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (j) 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. (k) Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes. (l) The amortization periods for other regulatory assets range up to 32 years and the amortization periods of other regulatory liabilities range up to 9 years. |
Member Power Bill Prepayments
Member Power Bill Prepayments | 6 Months Ended |
Jun. 30, 2018 | |
Member Power Bill Prepayments | |
Member Power Bill Prepayments | (J) 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 2023, with the majority of the balance scheduled to be credited by the end of 2019. |
Debt
Debt | 6 Months Ended |
Jun. 30, 2018 | |
Debt | |
Debt | (K) Debt. a) Department of Energy Loan Guarantee: 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 the Note Purchase Agreement dated as of February 20, 2014 (the Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank (the FFB Notes and together with the Note Purchase Agreement, the FFB Credit Facility Documents). The FFB Credit Facility 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 received under the Facility are used to reimburse us for a portion of certain costs of construction relating to Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program. Aggregate borrowings under the Facility may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the Federal Financing Bank under the 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 begin on February 20, 2020. Under both FFB Notes, the interest rates 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 June 30, 2018, aggregate Department of Energy-guaranteed borrowings totaled $1,764,658,000, including capitalized interest. Pursuant to the amended terms of the Loan Guarantee Agreement, no further advances are permitted pending satisfaction of certain conditions, including an amendment to the Loan Guarantee Agreement and a Co-owner vote to continue construction (discussed in Note L). When these conditions are satisfied, advances may be requested under the Facility on a quarterly basis through December 31, 2020. In addition to the conditions described above, future advances are subject to satisfaction of customary conditions, including certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, our continued ownership of our interest in Vogtle Units No. 3 and No. 4 free and clear of any liens except those permitted under the Loan Guarantee Agreement, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse eligible project costs. 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 an "Alternate Amortization Event," the Department of Energy may require us to prepay the outstanding principal amount of all guaranteed borrowings over a period of five years, with level principal amortization. These events include (i) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (ii) termination of the Services Agreement as defined in Note L or rejection of the Services Agreement in bankruptcy if Georgia Power does not maintain access to certain related intellectual property rights, (iii) a decision by us not to continue construction of Vogtle Units No. 3 and No. 4, (iv) loss of or failure to receive necessary regulatory approvals under certain circumstances, (v) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (vi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (vii) change of control of Oglethorpe and (viii) certain events of loss or condemnation. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility. 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 $1,619,679,706 of additional guaranteed funding under the Loan Guarantee Agreement. This conditional commitment expires on September 30, 2018, subject to any extension approved by the Department of Energy. We do not anticipate closing on the new loan before September 30, 2018 and anticipate seeking an extension from the Department of Energy. Final approval and issuance of this additional loan guarantee by the Department of Energy cannot be assured and is 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, including a vote of the Co-owners to continue construction. b) Rural Utilities Service Guaranteed Loans: For the six-month period ended June 30, 2018, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $236,200,000 for long-term financing of general and environmental improvements at existing plants. In July 2018, we received an additional $33,021,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. These advances are secured under our first mortgage indenture. c) Pollution Control Revenue Bonds: On December 28, 2017, the Development Authority of Burke County (Georgia) issued, on our behalf, $399,785,000 (Series 2017C, D, E, F Burke) in aggregate principal amount of tax-exempt pollution control revenue bonds to refinance costs associated with certain of our pollution control facilities. The bonds were directly purchased by two banks and the proceeds defeased our obligations under $399,785,000 of pollution control revenue bonds issued in 2008 that were callable on or after January 1, 2018. Those 2008 bonds were fully redeemed on their call date. Each series of the 2017 bonds bore interest at an indexed variable rate until February 1, 2018 when we converted the bonds into fixed interest rate modes. We converted the (i) $200,000,000 Series 2017C and Series 2017D bonds to a fixed rate of 4.125% per annum to maturity with an optional call at par on February 1, 2028, (ii) $100,000,000 Series 2017E bonds to a fixed term rate of 3.25% per annum to the mandatory tender date of February 3, 2025 and (iii) $99,785,000 Series 2017F bonds to a fixed term rate of 3.00% per annum to the mandatory tender date of February 1, 2023. The Series 2017C, D, E, F bonds are scheduled to mature in 2041 through 2045. Our payment obligations related to these bonds are secured under our first mortgage indenture. |
Vogtle Units No. 3 and No. 4 Co
Vogtle Units No. 3 and No. 4 Construction Project | 6 Months Ended |
Jun. 30, 2018 | |
Vogtle Units No. 3 and No. 4 Construction Project | |
Vogtle Units No. 3 and No. 4 Construction Project | (L) 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 two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our 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., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired in July 2017 upon the effective date of the Services Agreement. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel is 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, and not jointly, liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Pursuant to the loan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement prior to obtaining any further advances under the loan guarantee agreement. In November 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, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement 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 Vogtle Units No. 3 and No. 4 will not be recovered in retail rates; or (iv) an increase in the construction budget contained in Georgia Power's seventeenth Vogtle construction monitoring (VCM) report of more than $1,000,000,000 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. On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation to continue construction of Vogtle Units No. 3 and No. 4, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions change and assumptions upon which Georgia Power's seventeenth VCM report are based do not materialize, the Public Service Commission reserved the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in either appeal could have a material impact on our financial condition and results of operations. Georgia Power has advised us that it recently became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast of the cost to complete the project and engaged a third party to independently assess this analysis, forecast, and existing project controls for identifying budget variances. The capital costs estimated to complete construction are expected to increase by approximately $1.5 billion (our 30% share estimated at approximately $450 million). The increases are primarily due to changed assumptions related to the finalization of contract scopes and management responsibilities for Bechtel and over 60 subcontractors, craft labor incentives, as well as the related levels of project management, oversight and support, including field supervision and engineering support, required to complete the project. We, and the other Co-owners, are evaluating these increased capital costs along with a project-level contingency in a preliminary amount of approximately $800 million (our 30% share estimated at $240 million). We are also evaluating whether an additional Oglethorpe contingency is warranted as is consistent with our conservative budgeting practices. Further, improvements to the project control environment have been implemented and additional improvements will continue to be evaluated. We are currently in the process of evaluating the estimated increases to the project budget. The impact of these additional project costs on our budget will be substantially mitigated by approximately $500 million of contingency included in our existing budget. We are in the process of preparing a revised budget that would include capital costs, allowance for funds used during construction, our allocation of the project-level contingency as well as a potential, separate Oglethorpe contingency. If construction on the project continues, we anticipate that our project budget may increase from $7.0 billion to a range of $7.25 billion to $7.5 billion. A revised project budget will affect the timing and amount of the projected capital expenditures related to the Vogtle project previously disclosed, although the timing of such expenditures remains uncertain. Georgia Power has stated that it does not intend to seek rate recovery for its proportionate share of the additional capital costs in its nineteenth VCM report to be filed with the Georgia Public Service Commission. As a result of Georgia Power's decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction. The Co-owners are expected to conduct these votes in the third quarter of 2018, and each of Georgia Power, Oglethorpe and MEAG will have to affirmatively vote to continue construction. If the Co-owners vote to move forward, they will also approve a revised project budget. As of June 30, 2018, our total investment in the additional Vogtle units was approximately $3,396,731,000. In the event that fewer than 90% of the Co-owners determine to continue construction, we and the other Co-owners will assess options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, are not expected to change in connection with these budget revisions. However, any extension of the project schedule is currently estimated to result in additional base capital costs of approximately $30 million per month based on our ownership interests and allowance for funds used during construction of approximately $12.5 million per month per unit. Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse 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 actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of June 30, 2018. We have a $3,057,069,461 federal loan guarantee from the Department of Energy, under which we have borrowed $1,764,658,000 as of June 30, 2018. Pursuant to the terms of the loan guarantee agreement, no further advances are permitted pending satisfaction of certain conditions. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1,619,679,706 of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expires on September 30, 2018, subject to any extension approved by the Department of Energy. We do not anticipate closing on the new loan before September 30, 2018 and anticipate seeking an extension from the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of other conditions, including the Co-owners vote to continue construction. 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. We have also financed an additional $1,387,000,000 of the capital costs of the Vogtle units through capital market debt issuances. We anticipate financing any project costs not financed with Department of Energy in the capital markets. The timing and availability of funds under the Department of Energy loan guarantee will guide our decisions as to the timing of any capital markets offerings. As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity, availability, and/or cost escalation; procurement, fabrication, delivery, assembly and/or installation, including any required engineering changes, of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Monthly construction production targets required to maintain the current project schedule increase significantly later in 2018 through 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be deployed. Aspects of the Westinghouse AP1000 design are based on new technologies that are just beginning initial operation in the global nuclear industry at this scale. There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners. The ultimate outcome of these matters cannot be determined at this time. |
Fair Value (Tables)
Fair Value (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Fair Value | |
Schedule of assets and liabilities measured at fair value on a recurring basis | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using June 30, 2018 Quoted Prices in Significant Other Significant ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ — $ — International equity trust — — Corporate bonds and debt — US Treasury securities — — Mortgage backed securities — — Domestic mutual funds — — Municipal bonds — — Federal agency securities — — Non-US Gov't bonds & private placements — — Other — — Long-term investments: International equity trust — — Corporate bonds and debt — US Treasury securities — — Mortgage backed securities — — Domestic mutual funds — — Federal agency securities — — Treasury STRIPS — — Other — — Natural gas swaps — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using December 31, Quoted Prices in Significant Other ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ $ $ — International equity trust — Corporate bonds and debt — US Treasury securities — Mortgage backed securities — Domestic mutual funds — Municipal bonds — Federal agency securities — Other — Long-term investments: International equity trust — Corporate bonds and debt — US Treasury securities — Mortgage backed securities — Domestic mutual funds — Federal agency securities — Other — Natural gas swaps — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of changes in Level 3 assets measured at fair value on a recurring basis | ​ ​ ​ ​ ​ Three Months Ended Corporate bonds and debt ​ ​ ​ ​ ​ (dollars in thousands) Balance at March 31, 2018 $ Transfers to Level 3 Total gains or losses (realized/unrealized): Changes in net assets — ​ ​ ​ ​ ​ Balance at June 30, 2018 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Six Months Ended Corporate bonds and debt ​ ​ ​ ​ ​ (dollars in thousands) Balance at December 31, 2017 $ — Transfers to Level 3 Total gains or losses (realized/unrealized): Changes in net assets — ​ ​ ​ ​ ​ Balance at June 30, 2018 $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of estimated fair values of long-term debt, including current maturities | The estimated fair values of our long-term debt, including current maturities at June 30, 2018 and December 31, 2017 were as follows (in thousands): ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Carrying Fair Carrying Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Long-term debt $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Derivative Instruments | |
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year | ​ ​ ​ ​ ​ Year Natural Gas Swaps (in millions) ​ ​ ​ ​ ​ 2018 2019 2020 2021 2022 2023 ​ ​ ​ ​ ​ Total ​ ​ ​ ​ ​ |
Schedule of fair value of derivative instruments and effect on consolidated balance sheets | The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet Fair Value ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ 2018 2017 (dollars in thousands) Assets: Natural gas swaps Other current assets $ $ Liabilities: Natural gas swaps Other current liabilities $ $ Natural gas swaps Other deferred credits $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of the realized gains and (losses) on derivative instruments recognized in margin | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Statement of Three months Six months 2018 2017 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Natural Gas Swaps Fuel $ $ $ $ Natural Gas Swaps Fuel ) ) ) ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of unrealized losses on derivative instruments deferred on the balance sheet | The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Balance Sheet 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) Natural gas swaps Regulatory asset $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ ) $ ) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Investments in Debt and Equit21
Investments in Debt and Equity Securities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Investments in Debt and Equity Securities | |
Summary of debt and equity securities | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Unrealized ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) June 30, 2018 Cost Gains Losses Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other — — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Gross Unrealized ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) December 31, 2017 Cost Gains Losses Fair ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Equity $ $ $ ) $ Debt ) Other — ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ ) $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Revenue Recognition | |
Schedule of sales to members | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Three Months Six Months (dollars in thousands) (dollars in thousands) 2018 2017 2018 2017 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Capacity revenues $ $ $ $ Energy revenues ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Total $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Schedule of opening and closing balances of receivables from contracts with customers | ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ June 30, June 30, December 31, December 31, ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Receivables from members $ $ $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ |
Regulatory Assets and Liabili23
Regulatory Assets and Liabilities (Tables) | 6 Months Ended |
Jun. 30, 2018 | |
Regulatory Assets and Liabilities | |
Schedule of regulatory assets and liabilities | The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of June 30, 2018 and December 31, 2017. ​ ​ ​ ​ ​ ​ ​ ​ 2018 2017 (dollars in thousands) ​ ​ ​ ​ ​ ​ ​ ​ Regulatory Assets: Premium and loss on reacquired debt (a) $ $ Amortization on capital leases (b) Outage costs (c) Asset retirement obligations—Ashpond and other (k) Depreciation expense (d) Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) Interest rate options cost (f) Deferral of effects on net margin—Smith Energy Facility (g) Other regulatory assets (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Assets $ $ Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ $ Deferral of effects on net margin—Hawk Road Energy Facility (g) Major maintenance reserve (i) Amortization on capital leases (b) Deferred debt service adder (j) Asset retirement obligations—Nuclear (k) Other regulatory liabilities (l) ​ ​ ​ ​ ​ ​ ​ ​ Total Regulatory Liabilities $ $ ​ ​ ​ ​ ​ ​ ​ ​ Net Regulatory Assets $ $ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ (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 26 years. (b) Represents the difference between expense recognized for rate-making purposes and financial statement purposes related to capital lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 48 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle, we deferred the difference between Plant Vogtle depreciation expense based on the then 40-year operating license and depreciation expense assuming an expected 20-year license extension. Amortization commenced upon NRC approval of the license extension in 2009 and is being amortized over the remaining life of the plant. (e) Deferred charges related to Vogtle Units No. 3 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. (f) Deferral of premiums paid to purchase interest rate options to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No.3 and No.4. Amortization will commence in February 2020 and will be amortized through February 2044, the life of the DOE-guaranteed loan which is financing a portion of the construction project. (g) 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. (h) Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets. (i) Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred. (j) 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. (k ) Represents difference in timing of recognition of the costs of decommissioning and ashpond remediation for financial statement purposes and for ratemaking purposes. (l) The amortization periods for other regulatory assets range up to 32 years and the amortization periods of other regulatory liabilities range up to 9 years. |
General (Details)
General (Details) | 6 Months Ended | |
Jun. 30, 2018USD ($)item | Jun. 30, 2017USD ($) | |
Number of electric distribution cooperative members | item | 38 | |
Refund liability | $ 5,650,000 | $ 5,750,000 |
ASU 2014-09 | ||
Refund liability | $ 5,650,000 | $ 5,750,000 |
Fair Value - Asset and liabilit
Fair Value - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($) | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Fair value measurement | ||
Long-term investments | $ 151,399,000 | $ 140,622,000 |
Natural gas swaps | ||
Fair value measurement | ||
Derivative liabilities | 11,382,000 | 6,328,000 |
International equity trust | ||
Fair value measurement | ||
Unfunded commitments | $ 0 | |
Redemption notice period | 3 days | |
Recurring basis | Natural gas swaps | ||
Fair value measurement | ||
Derivative liabilities | $ 11,382,000 | 6,328,000 |
Recurring basis | Domestic equity | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 146,480,000 | 142,419,000 |
Recurring basis | International equity trust | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 86,840,000 | 88,820,000 |
Long-term investments | 19,632,000 | 20,071,000 |
Recurring basis | Corporate bonds and debt | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 51,481,000 | 66,317,000 |
Long-term investments | 13,200,000 | 16,215,000 |
Recurring basis | US Treasury securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 42,148,000 | 38,791,000 |
Long-term investments | 7,643,000 | 6,670,000 |
Recurring basis | Mortgage backed securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 56,752,000 | 49,379,000 |
Long-term investments | 11,062,000 | 7,267,000 |
Recurring basis | Domestic mutual funds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 50,776,000 | 47,833,000 |
Long-term investments | 91,714,000 | 87,011,000 |
Recurring basis | Municipal bonds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 288,000 | 92,000 |
Recurring basis | Federal agency securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 5,164,000 | 3,725,000 |
Long-term investments | 452,000 | 259,000 |
Recurring basis | Non-US Gov't bonds & private placements | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 1,466,000 | |
Recurring basis | Treasury STRIPS | ||
Fair value measurement | ||
Long-term investments | 4,641,000 | |
Recurring basis | Other | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 5,590,000 | 7,679,000 |
Long-term investments | 3,055,000 | 3,129,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 146,480,000 | 142,419,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 42,148,000 | 38,791,000 |
Long-term investments | 7,643,000 | 6,670,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 50,776,000 | 47,833,000 |
Long-term investments | 91,714,000 | 87,011,000 |
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 5,590,000 | 7,679,000 |
Long-term investments | 3,055,000 | 3,129,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps | ||
Fair value measurement | ||
Derivative liabilities | 11,382,000 | 6,328,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 86,840,000 | 88,820,000 |
Long-term investments | 19,632,000 | 20,071,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 48,172,000 | 66,317,000 |
Long-term investments | 11,512,000 | 16,215,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 56,752,000 | 49,379,000 |
Long-term investments | 11,062,000 | 7,267,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 288,000 | 92,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 5,164,000 | 3,725,000 |
Long-term investments | 452,000 | $ 259,000 |
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 1,466,000 | |
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS | ||
Fair value measurement | ||
Long-term investments | 4,641,000 | |
Recurring basis | Significant Unobservable Inputs (Level 3) | Corporate bonds and debt | ||
Fair value measurement | ||
Nuclear decommissioning trust funds | 3,309,000 | |
Long-term investments | $ 1,688,000 |
Fair Value - Changes in Level 3
Fair Value - Changes in Level 3 assets (Details) - Total Fair Value - Significant Unobservable Inputs (Level 3) - Recurring basis - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |
Jun. 30, 2018 | Jun. 30, 2018 | Dec. 31, 2017 | |
Changes in Level 3 assets and liabilities measured at fair value on a recurring basis | |||
Balance at the beginning of the period | $ 3,807 | ||
Transfers to Level 3 | 1,190 | $ 4,997 | |
Balance at the end of the period | $ 4,997 | $ 4,997 | |
Financial assets having unobservable inputs classified as Level 3 | $ 0 | ||
Financial liabilities having unobservable inputs classified as Level 3 | $ 0 |
Fair Value - Estimated fair val
Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands | Jun. 30, 2018 | Dec. 31, 2017 |
Carrying Value | ||
Grouping Financial Statement Captions | ||
Long-term debt | $ 8,423,001 | $ 8,232,703 |
Total Fair Value | ||
Grouping Financial Statement Captions | ||
Long-term debt | $ 8,947,616 | $ 9,155,942 |
Derivative Instruments - Notion
Derivative Instruments - Notional volume of natural gas derivatives (Details) - Natural gas swaps item in Millions | Jun. 30, 2018USD ($)item | Dec. 31, 2017USD ($) |
Gas hedges | ||
Derivative liabilities | $ | $ 11,382,000 | $ 6,328,000 |
Collateral or letters of credit required to be posted with counterparties, if credit-risk-related contingent features were triggered due to credit rating being downgraded below investment grade | $ | $ 11,382,000 | |
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 83.1 | |
2,018 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 15.4 | |
2,019 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 21.6 | |
2,020 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 18.4 | |
2,021 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 16.8 | |
2,022 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 10.7 | |
2,023 | ||
Gas hedges | ||
Derivative volume activity that is expected to settle or mature each year (in MMBTUs) | 0.2 |
Derivative Instruments - Fair v
Derivative Instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) | Jun. 30, 2018 | Dec. 31, 2017 |
Liabilities: | ||
Fair value of liabilities | $ 11,382,000 | $ 6,328,000 |
Other current assets | ||
Assets: | ||
Fair value of assets | 1,228,000 | 412,000 |
Other current liabilities | ||
Liabilities: | ||
Fair value of liabilities | 747,000 | 1,575,000 |
Other deferred credits | ||
Liabilities: | ||
Fair value of liabilities | $ 11,863,000 | $ 5,165,000 |
Derivative Instruments - Realiz
Derivative Instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands | 3 Months Ended | 6 Months Ended | |||
Jun. 30, 2018 | Jun. 30, 2017 | Jun. 30, 2018 | Jun. 30, 2017 | Dec. 31, 2017 | |
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||||
Total unrealized gains (losses) | $ (11,382) | $ (11,382) | $ (6,328) | ||
Natural gas swaps | Regulatory asset | |||||
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||||
Unrealized losses on derivatives | (11,382) | (11,382) | $ (6,328) | ||
Natural gas swaps | Fuel | |||||
Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses or Balance Sheet | |||||
Gains | 359 | $ 1,897 | 1,751 | $ 2,736 | |
Losses | (111) | (73) | (859) | (817) | |
Total | $ 248 | $ 1,824 | $ 892 | $ 1,919 |
Investments in Debt and Equit31
Investments in Debt and Equity Securities (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Available-for-sale securities | ||
Available-for-sale securities, gross unrealized losses that were in effect for less than one year (as a percent) | 66.00% | |
Cost | $ 511,322 | $ 498,234 |
Gains | 97,034 | 93,769 |
Losses | (9,972) | (6,326) |
Fair Value | 598,384 | 585,677 |
Equity | ||
Available-for-sale securities | ||
Cost | 248,817 | 246,549 |
Gains | 96,340 | 91,954 |
Losses | (4,885) | (4,064) |
Fair Value | 340,272 | 334,439 |
Debt | ||
Available-for-sale securities | ||
Cost | 253,860 | 240,878 |
Gains | 694 | 1,814 |
Losses | (5,087) | (2,262) |
Fair Value | 249,467 | 240,430 |
Other | ||
Available-for-sale securities | ||
Cost | 8,645 | 10,807 |
Gains | 1 | |
Fair Value | $ 8,645 | $ 10,808 |
Recently Issued or Adopted Ac32
Recently Issued or Adopted Accounting Pronouncements (Details) - USD ($) | 6 Months Ended | ||
Jun. 30, 2018 | Dec. 31, 2017 | Jun. 30, 2017 | |
Recently Issued or Adopted Accounting Pronouncements | |||
Regulatory assets | $ 597,611,000 | $ 585,084,000 | |
Refund liability | 5,650,000 | $ 5,750,000 | |
ASU 2014-09 | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Refund liability | $ 5,650,000 | $ 5,750,000 | |
ASU 2016-01 | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Regulatory assets | $ 618,000 | ||
ASU 2016-02 | |||
Recently Issued or Adopted Accounting Pronouncements | |||
Percentage of undivided interest | 60.00% |
Revenue Recognition (Details)
Revenue Recognition (Details) | 3 Months Ended | 6 Months Ended | 12 Months Ended | ||||
Jun. 30, 2018USD ($) | Jun. 30, 2017USD ($) | Jun. 30, 2018USD ($)item | Jun. 30, 2017USD ($) | Dec. 31, 2018 | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | |
Revenue Recognition | |||||||
Number of electric distribution cooperative members | item | 38 | ||||||
Number of services provided | item | 2 | ||||||
Margins for interest ratio | 1.10 | ||||||
Targeted margins for interest ratio | 1.14 | ||||||
Achieved margins for interest ratio | 1.14 | ||||||
Refund liability | $ 5,650,000 | $ 5,750,000 | $ 5,650,000 | $ 5,750,000 | |||
Total | 365,921,000 | 361,369,000 | $ 739,567,000 | 715,539,000 | |||
Period in which payment is due following billing | 1 month | ||||||
Impairment losses | 0 | 0 | $ 0 | 0 | |||
Members | |||||||
Revenue Recognition | |||||||
Total | 365,811,000 | 361,323,000 | 739,212,000 | 715,467,000 | |||
Receivables | 144,865,000 | 132,703,000 | 144,865,000 | 132,703,000 | $ 126,211,000 | $ 136,552,000 | |
Non-Members | |||||||
Revenue Recognition | |||||||
Total | 110,000 | 46,000 | 355,000 | 72,000 | |||
Capacity revenues | Members | |||||||
Revenue Recognition | |||||||
Total | 231,571,000 | 229,946,000 | 472,052,000 | 467,377,000 | |||
Energy revenues | Members | |||||||
Revenue Recognition | |||||||
Total | $ 134,240,000 | $ 131,377,000 | $ 267,160,000 | $ 248,090,000 |
Restricted Investments (Details
Restricted Investments (Details) - USD ($) | 6 Months Ended | 12 Months Ended |
Jun. 30, 2018 | Dec. 31, 2017 | |
Restricted Investments | ||
Guaranteed interest rate on deposit (as a percent) | 5.00% | 5.00% |
Restricted investments | $ 805,100,000 | $ 882,909,000 |
Restricted investments, long-term | $ 585,111,000 | $ 653,585,000 |
Regulatory Assets and Liabili35
Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | 6 Months Ended | |
Jun. 30, 2018 | Dec. 31, 2017 | |
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 597,611 | $ 585,084 |
Total Regulatory Liabilities | 253,683 | 251,649 |
Net Regulatory Assets | 343,928 | 333,435 |
Accumulated retirement costs for other obligations | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 16,112 | 12,813 |
Deferral of effects on net margin | Hawk Road Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 19,247 | 19,553 |
Major maintenance reserve | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 50,084 | 47,087 |
Amortization on capital leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 18,605 | 20,055 |
Deferred debt service adder | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 100,447 | 95,695 |
Asset retirement obligations | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | 40,334 | 53,571 |
Other regulatory liabilities | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Liabilities | $ 8,854 | 2,875 |
Other regulatory liabilities | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization Period | 9 years | |
Premium and loss on reacquired debt | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 49,647 | 52,989 |
Premium and loss on reacquired debt | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 26 years | |
Amortization on capital leases | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 34,382 | 33,846 |
Outage costs | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 34,715 | 40,525 |
Coal-fired maintenance outage costs | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 48 months | |
Nuclear refueling outage costs | Minimum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 18 months | |
Nuclear refueling outage costs | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 24 months | |
Asset retirement obligations | Ashpond and other | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 85,449 | 68,289 |
Depreciation expense | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 41,955 | 42,667 |
Depreciation expense | Plant Vogtle | ||
Regulatory Assets and Liabilities | ||
Operating license expected extension period for Plant Vogtle | 20 years | |
Operating license period | 40 years | |
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs | Vogtle Units Number 3 And Number 4 | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 50,188 | 48,702 |
Interest rate options cost | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 114,515 | 112,102 |
Deferral of effects on net margin | Smith Energy Facility | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | 163,482 | 166,454 |
Other regulatory assets | ||
Regulatory Assets and Liabilities | ||
Total Regulatory Assets | $ 23,278 | $ 19,510 |
Other regulatory assets | Maximum | ||
Regulatory Assets and Liabilities | ||
Amortization period, other regulatory assets | 32 years |
Debt (Details)
Debt (Details) | Dec. 28, 2017USD ($)item | Jul. 31, 2018USD ($) | Jun. 30, 2018USD ($) | Sep. 28, 2017USD ($) | Feb. 20, 2014item |
Loan Guarantee Agreement | |||||
Debt | |||||
Number of future advance promissory notes | item | 2 | ||||
Spread on variable rate (as a percent) | 0.375% | ||||
Aggregate Department of Energy-guaranteed borrowings | $ 1,764,658,000 | ||||
Term of credit facility (in years) | 5 years | ||||
Period of cessation of construction activities which would result in prepayment of outstanding principal | 12 months | ||||
Period of failure to fund operation and maintenance expenses which would result in prepayment of outstanding principal | 12 months | ||||
Loan Guarantee Agreement | Maximum | |||||
Debt | |||||
Aggregate borrowings | $ 3,057,069,461 | ||||
Capitalized interest | 335,471,604 | ||||
Conditional commitment issued by guarantor under the Loan Guarantee Agreement | $ 1,619,679,706 | ||||
Rural Utilities Service Guaranteed Loans | |||||
Debt | |||||
Proceeds from issuance of debt | $ 33,021,000 | $ 236,200,000 | |||
First mortgage notes issued in connection with the sale of pollution control revenue bonds: Series 2017 CDEF Burke | |||||
Debt | |||||
Principal amount | $ 399,785,000 | ||||
Repayments of debt, defeasance | $ 399,785,000 | ||||
Number of banks | item | 2 | ||||
Pollution Control Revenue Bonds Series 2017C and Series 2017D | |||||
Debt | |||||
Principal amount | $ 200,000,000 | ||||
Fixed rate interest (as a percent) | 4.125% | ||||
Pollution Control Revenue Bonds Series 2017E | |||||
Debt | |||||
Principal amount | $ 100,000,000 | ||||
Fixed rate interest (as a percent) | 3.25% | ||||
Pollution Control Revenue Bonds Series 2017F | |||||
Debt | |||||
Principal amount | $ 99,785,000 | ||||
Fixed rate interest (as a percent) | 3.00% |
Vogtle Units No. 3 and No. 4 37
Vogtle Units No. 3 and No. 4 Construction Project (Details) | 1 Months Ended | 6 Months Ended | 12 Months Ended | ||
Nov. 30, 2017USD ($) | Jun. 30, 2018USD ($)item | Dec. 31, 2008itemMW | Dec. 31, 2018USD ($) | Sep. 28, 2017USD ($) | |
Loan Guarantee Agreement | |||||
Electric plant, construction and related agreements | |||||
Aggregate Department of Energy-guaranteed borrowings | $ 1,764,658,000 | ||||
Term of credit facility (in years) | 5 years | ||||
Loan Guarantee Agreement | Maximum | |||||
Electric plant, construction and related agreements | |||||
Aggregate borrowings | $ 3,057,069,461 | ||||
Conditional commitment issued by guarantor under the Loan Guarantee Agreement | $ 1,619,679,706 | ||||
Services Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||||
Electric plant, construction and related agreements | |||||
Written notice period for termination of agreement | 30 days | ||||
Joint Ownership Agreements | Minimum | |||||
Electric plant, construction and related agreements | |||||
Ownership interests voting required to continue construction (as a percent) | 90.00% | ||||
Increase in project budget | $ 1,000,000,000 | ||||
Project extension term | 1 year | ||||
Ownership approval to change primary construction contractor (as a percent) | 90.00% | ||||
Ownership approval required for material amendments (as a percent) | 67.00% | ||||
Vogtle Units Number 3 And Number 4 | |||||
Electric plant, construction and related agreements | |||||
Number of petitions filed by parties | item | 2 | ||||
Estimated additional costs of completion | $ 450,000,000 | ||||
Number of subcontractors | item | 60 | ||||
Estimated increase in construction contingency | $ 240,000,000 | ||||
Estimated construction contingency | 500,000,000 | ||||
Project budget | 7,000,000,000 | ||||
Total investment in additional vogtle units | 3,396,731,000 | ||||
Capital market debt issuances | 1,387,000,000 | ||||
Vogtle Units Number 3 And Number 4 | Extension of the project schedule | |||||
Electric plant, construction and related agreements | |||||
Estimate of additional base capital monthly costs | 30,000,000 | ||||
Estimate of additional allowance for funds used during construction monthly per unit costs | $ 12,500,000 | ||||
Vogtle Units Number 3 And Number 4 | Minimum | Forecast | |||||
Electric plant, construction and related agreements | |||||
Project budget estimated minimum | $ 7,250,000,000 | ||||
Vogtle Units Number 3 And Number 4 | Maximum | Forecast | |||||
Electric plant, construction and related agreements | |||||
Project budget estimated maximum | $ 7,500,000,000 | ||||
Vogtle Units Number 3 And Number 4 | Ownership participation agreement | |||||
Electric plant, construction and related agreements | |||||
Number of additional nuclear units | item | 2 | ||||
Ownership interest (as a percent) | 30.00% | ||||
Vogtle Units Number 3 And Number 4 | Engineering, Procurement and Construction Agreement (the EPC Agreement) | Westinghouse Electric Company LLC and Stone & Webster, Inc. | |||||
Electric plant, construction and related agreements | |||||
Number of nuclear units | item | 2 | ||||
Generating capacity of each nuclear unit | MW | 1,100 | ||||
Co-owners | Vogtle Units Number 3 And Number 4 | |||||
Electric plant, construction and related agreements | |||||
Estimated additional costs of completion | $ 1,500,000,000 | ||||
Estimated construction project-level contingency | $ 800,000,000 |