Oglethorpe Power 10-Q 13 Nov 19 2019 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information	9 Months Ended
	Sep. 30, 2019shares
Document and Entity Information
Entity Registrant Name	OGLETHORPE POWER CORP
Document Type	10-Q
Document Period End Date	Sep. 30, 2019
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	0
Entity Central Index Key	0000788816
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	Q3
Amendment Flag	false

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Electric plant:
In service	$ 9,184,450,000	$ 8,981,238,000
Right-of-use assets - finance leases	302,732,000	302,732,000
Less: Accumulated provision for depreciation	(4,805,514,000)	(4,544,405,000)
Net in service	4,681,668,000	4,739,565,000
Nuclear fuel, at amortized cost	351,874,000	358,358,000
Construction work in progress	4,515,150,000	3,866,042,000
Total electric plant	9,548,692,000	8,963,965,000
Investments and funds:
Nuclear decommissioning trust fund	483,235,000	420,818,000
Investment in associated companies	73,533,000	77,037,000
Long-term investments	208,024,000	164,125,000
Restricted investments	513,193,000	503,158,000
Other	24,996,000	24,259,000
Total investments and funds	1,302,981,000	1,189,397,000
Current assets:
Cash and cash equivalents	427,039,000	752,618,000
Restricted short-term investments	50,790,000	150,000,000
Receivables	158,451,000	153,647,000
Inventories, at average cost	272,353,000	259,087,000
Prepayments and other current assets	10,126,000	8,098,000
Total current assets	918,759,000	1,323,450,000
Deferred charges:
Regulatory assets	773,780,000	655,063,000
Prepayments to Georgia Power	40,346,000	29,459,000
Other	23,520,000	21,934,000
Total deferred charges	837,646,000	706,456,000
Total assets	12,608,078,000	12,183,268,000
Capitalization:
Patronage capital and membership fees	1,013,551,000	962,286,000
Long-term debt	8,871,910,000	8,727,148,000
Obligation under finance leases	78,771,000	81,730,000
Other	24,977,000	21,428,000
Total capitalization	9,989,209,000	9,792,592,000
Current liabilities:
Long-term debt and finance leases due within one year	196,489,000	522,289,000
Short-term borrowings	560,671,000
Accounts payable	141,185,000	206,577,000
Accrued interest	67,118,000	60,971,000
Member power bill prepayments, current	107,695,000	224,957,000
Other current liabilities	72,960,000	49,465,000
Total current liabilities	1,146,118,000	1,064,259,000
Deferred credits and other liabilities:
Asset retirement obligations	1,057,560,000	1,017,563,000
Member power bill prepayments, non-current	77,614,000	54,750,000
Regulatory liabilities	299,527,000	218,998,000
Other	38,050,000	35,106,000
Total deferred credits and other liabilities	1,472,751,000	1,326,417,000
Total equity and liabilities	$ 12,608,078,000	$ 12,183,268,000

Consolidated Statements of Reve

Consolidated Statements of Revenues and Expenses - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Operating revenues:
Total operating revenues	$ 382,623	$ 384,644	$ 1,098,083	$ 1,124,211
Operating expenses:
Fuel	138,704	151,903	349,146	394,494
Production	93,092	95,971	301,996	299,134
Depreciation and amortization	60,574	56,936	183,212	170,565
Purchased power	17,716	15,381	50,415	46,030
Accretion	13,328	9,608	36,361	28,364
Total operating expenses	323,414	329,799	921,130	938,587
Operating margin	59,209	54,845	176,953	185,624
Other income:
Investment income	14,144	15,242	45,129	43,925
Other	623	1,765	1,565	5,383
Total other income	14,767	17,007	46,694	49,308
Interest charges:
Interest expense	100,687	95,958	301,864	280,385
Allowance for debt funds used during construction	(47,909)	(38,589)	(138,246)	(110,670)
Amortization of debt discount and expense	2,912	3,149	8,764	9,198
Net interest charges	55,690	60,518	172,382	178,913
Net margin	18,286	11,334	51,265	56,019
Members
Operating revenues:
Total operating revenues	382,548	384,529	1,097,754	1,123,741
Non-Members
Operating revenues:
Total operating revenues	$ 75	$ 115	$ 329	$ 470

Consolidated Statements of Patr

Consolidated Statements of Patronage Capital and Membership Fees - USD ($) $ in Thousands	3 Months Ended						9 Months Ended
	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Sep. 30, 2019	Sep. 30, 2018
Components of comprehensive margin:
Net margin	$ 18,286			$ 11,334			$ 51,265	$ 56,019
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Beginning balance	995,265	$ 985,882	$ 962,286	955,771	$ 938,486	$ 911,087	962,286	911,087
Components of comprehensive margin:
Net margin	18,286	9,383	23,596	11,335	17,285	27,399
Ending balance	$ 1,013,551	$ 995,265	$ 985,882	$ 967,106	$ 955,771	$ 938,486	$ 1,013,551	$ 967,106

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Cash flows from operating activities:
Net margin	$ 51,265	$ 56,019
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	281,049	277,209
Accretion cost	36,361	28,364
Amortization of deferred gains	(1,341)	(1,341)
Allowance for equity funds used during construction	(569)	(708)
Deferred outage costs	(26,925)	(23,761)
(Gain) loss on sale of investments	(4,611)	3,886
Regulatory deferral of costs associated with nuclear decommissioning	(17,686)	(20,019)
Other	(549)	(4,564)
Change in operating assets and liabilities:
Receivables	(1,706)	(14,580)
Inventories	(13,238)	16,209
Prepayments and other current assets	(2,256)	2,535
Accounts payable	(60,068)	(6,098)
Accrued interest	6,147	1,298
Accrued taxes	34,435	12,312
Other current liabilities	(26,761)	(11,743)
Member power bill prepayments	(94,398)	67,461
Other	37,982	10,866
Total adjustments	145,866	337,326
Net cash provided by operating activities	197,131	393,345
Cash flows from investing activities:
Property additions	(887,160)	(852,225)
Activity in nuclear decommissioning trust fund - Purchases	(281,821)	(360,801)
Activity in nuclear decommissioning trust fund - Proceeds	275,545	354,897
Decrease in restricted investments	89,175	127,662
Activity in other long-term investments - Purchases	(165,743)	(160,813)
Activity in other long-term investments - Proceeds	134,907	135,673
Other	(9,674)	8,331
Net cash used in investing activities	(844,771)	(747,276)
Cash flows from financing activities:
Long-term debt proceeds	683,008	280,257
Long-term debt payments	(477,360)	(117,684)
Increase in short-term borrowings, net	124,044	505,397
Other	(7,631)	6,180
Net cash provided by financing activities	322,061	674,150
Net (decrease) increase in cash and cash equivalents	(325,579)	320,219
Cash and cash equivalents at beginning of period	752,618	397,695
Cash and cash equivalents at end of period	427,039	717,914
Cash paid for -
Interest (net of amounts capitalized)	156,370	166,134
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	5,053	2,404
Accrued property additions at end of period	103,390	144,372
Interest paid-in-kind	$ 55,767	$ 44,040

General

General	9 Months Ended
	Sep. 30, 2019
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 nine-month periods ended September 30, 2019 and 2018. Examples of estimates used include items related to (i) our asset retirement obligations, such as closure and post-closure cost estimates, timing of expenditures, escalation factors and discount rates, and (ii) revenue recognition, such as determining the nature and timing of satisfaction of performance obligations, determining the standalone selling price of performance obligations and variable consideration. Actual results may differ from those estimates. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to SEC rules and regulations, although we believe that the disclosures are adequate to make the information presented not misleading. Certain prior year amounts have been reclassified to conform with current year presentation. These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2018, as filed with the SEC. The results of operations for the three- and nine-month periods ended September 30, 2019 are not necessarily indicative of results to be expected for the full year. As noted in our 2018 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 2018 Form 10-K.

Fair Value

Fair Value	9 Months Ended
	Sep. 30, 2019
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 September 30, 2019 and December 31, 2018. Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs September 30, 2019 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 164,319 $ 164,319 $ — $ — International equity trust 88,037 — 88,037 — Corporate bonds and debt 62,039 — 62,039 — US Treasury securities 53,744 53,744 — — Mortgage backed securities 54,803 — 54,803 — Domestic mutual funds 50,990 50,990 — — Municipal bonds 1,237 — 1,237 — Federal agency securities 2,197 — 2,197 — Non-US Gov't bonds & private placements 272 — 272 — Other 5,597 5,597 — — Long-term investments: International equity trust 21,190 — 21,190 — Corporate bonds and debt 18,340 — 18,340 — US Treasury securities 9,772 9,772 — — Mortgage backed securities 13,246 — 13,246 — Domestic mutual funds 94,772 94,772 — — Federal agency securities 46 — 46 — Treasury STRIPS 48,058 — 48,058 — Other 2,600 2,600 — — Natural gas swaps 26,379 — 26,379 — Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs December 31, 2018 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 136,196 $ 136,196 $ — $ — International equity trust 76,852 — 76,852 — Corporate bonds and debt 51,356 — 48,853 2,503 US Treasury securities 47,712 47,712 — — Mortgage backed securities 56,004 — 56,004 — Domestic mutual funds 43,359 43,359 — — Municipal bonds 278 — 278 — Federal agency securities 6,066 — 6,066 — Non-US Gov't bonds & private placements 964 — 964 — Other 2,031 2,031 — — Long-term investments: International equity trust 17,382 — 17,382 — Corporate bonds and debt 12,571 — 11,366 1,205 US Treasury securities 12,062 12,062 — — Mortgage backed securities 11,517 — 11,517 — Domestic mutual funds 94,494 94,494 — — Federal agency securities 941 — 941 — Treasury STRIPS 14,113 — 14,113 — Other 1,045 1,045 — — Natural gas swaps 13,154 — 13,154 — 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 exchanged 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 nine months ended September 30, 2019 and 2018. Three Months Ended September 30, 2019 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at June 30, 2019 $ — Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) — Liquidations — Balance at September 30, 2019 $ — Nine Months Ended September 30, 2019 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at December 31, 2018 $ 3,708 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) 94 Liquidations (3,802) Balance at September 30, 2019 $ — Three Months Ended September 30, 2018 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at June 30, 2018 $ 4,997 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) (656) Balance at September 30, 2018 $ 4,341 Nine Months Ended September 30, 2018 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at December 31, 2017 $ — Transfers to Level 3 4,997 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) (656) Balance at September 30, 2018 $ 4,341 The estimated fair values of our long‑term debt, including current maturities at September 30, 2019 and December 31, 2018 were as follows (in thousands): 2019 2018 Carrying Value Fair Value Carrying Value Fair Value Long-term debt $ $ $ 9,347,307 $ 9,837,254 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 September 30, 2019 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 and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2019
Derivative Instruments
Derivative Instruments	(C) Derivative Instruments. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statement of cash flows. We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty’s nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions. It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of September 30, 2019, 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. 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 September 30, 2019 and December 31, 2018, the estimated fair values of our natural gas contracts were net liabilities of approximately $26,379,000 and $13,154,000, respectively. As of September 30, 2019 and December 31, 2018, 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 September 30, 2019 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $26,379,000 with our counterparties. The following table reflects the notional volume of our natural gas derivatives as of September 30, 2019 that is expected to settle or mature each year: Natural Gas Swaps (MMBTUs) Year (in millions) 2019 3.5 2020 24.9 2021 22.0 2022 15.3 2023 10.2 2024 7.2 Total 83.1 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 2019 and December 31, 2018. Balance Sheet Location Fair Value 2019 2018 (dollars in thousands) Assets: Natural gas swaps Other current assets $ — $ 226 Liabilities: Natural gas swaps Other current liabilities $ 10,435 $ 2,066 Natural gas swaps Other deferred credits $ 15,944 $ 11,314 The following table presents the gross realized gains and (losses) on derivative instruments recognized in margin for the three and nine months ended September 30, 2019 and 2018. Statement of Three months Nine months Revenues and ended ended Expenses September 30, September 30, Location 2019 2018 2019 2018 (dollars in thousands) Natural Gas Swaps gains Fuel $ — $ 863 $ 224 $ 2,614 Natural Gas Swaps losses Fuel (6,294) (97) (8,093) (956) Total $ (6,294) $ 766 $ (7,869) $ 1,658 The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at September 30, 2019 and December 31, 2018. Balance Sheet Location 2019 2018 (dollars in thousands) Natural gas swaps Regulatory asset $ 26,379 $ 13,154 Total $ 26,379 $ 13,154

Investments in Debt and Equity

Investments in Debt and Equity Securities	9 Months Ended
	Sep. 30, 2019
Investments in Debt and Equity Securities
Investments in Debt and Equity Securities	(D) Investments in Debt and Equity Securities. Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. At September 30, 2019, investments with a fair value of $22,298,000 were in an unrealized loss position for greater than one year and represented approximately 78% of our gross unrealized losses, while investments with a fair value of $35,640,000 were in an unrealized loss position for less than one year. At December 31, 2018, investments with a fair value of $49,975,000 were in an unrealized loss position for greater than one year and represented approximately 59% of our gross unrealized losses, while investments with a fair value of $148,638,000 were in an unrealized loss position for less than one year. The following tables summarize debt and equity securities as of September 30, 2019 and December 31, 2018. Gross Unrealized (dollars in thousands) Fair September 30, 2019 Cost Gains Losses Value Equity $ 256,835 $ 114,881 $ (7,298) $ 364,418 Debt 309,021 10,185 (563) 318,643 Other 8,198 — — 8,198 Total $ 574,054 $ 125,066 $ (7,861) $ 691,259 Gross Unrealized (dollars in thousands) Fair December 31, 2018 Cost Gains Losses Value Equity $ 251,226 $ 64,954 $ (9,105) $ 307,075 Debt 278,030 1,718 (4,955) 274,793 Other 3,075 — — 3,075 Total $ 532,331 $ 66,672 $ (14,060) $ 584,943

Recently Issued or Adopted Acco

Recently Issued or Adopted Accounting Pronouncements	9 Months Ended
	Sep. 30, 2019
Recently Issued or Adopted Accounting Pronouncements
Recently Issued or Adopted Accounting Pronouncements	(E) Recently Issued or Adopted Accounting Pronouncements. In February 2016, the FASB issued “Leases (Topic 842).” The new leases standard requires a dual approach for lessee accounting under which a lessee accounts for leases as finance leases or operating leases. Accounting for both finance leases and operating leases results in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability. For finance leases the lessee recognizes interest expense and amortization of the ROU asset and for operating leases the lessee recognizes a straight-line total lease expense. Quantitative and qualitative disclosures are required for significant judgments made by management. The new lease standard does not substantially change lessor accounting. We adopted the new standard effective January 1, 2019. For additional information, see Note G. 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. Early adoption is permitted. We continue to evaluate the future impact of this standard on our consolidated financial statements, however, we do not expect the impact to be material. In August 2018, the FASB issued “Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement.” This standard eliminates, adds and modifies certain disclosure requirements for fair value measurements as part of the FASB's disclosure framework project. Entities will no longer be required to disclose the amount of and reasons for transfers between Level 1 and Level 2 of the fair value hierarchy, the policy for timing of transfers between levels and the valuation processes for Level 3 fair value measurements. However, public business entities will be required to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The amendments in this update are effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. An entity is permitted to early adopt any removed or modified disclosures upon issuance of this update and delay adoption of the additional disclosures until their effective date. As the standard relates only to disclosures, we do not expect the adoption of this standard to have a material impact on our consolidated financial statements. We are currently evaluating the standard and whether we will early adopt the standard.

Revenue Recognition

Revenue Recognition	9 Months Ended
	Sep. 30, 2019
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 to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. 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 the wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. Revenues from our members are derived through a cost-plus rate structure which is set forth as a formula in the rate schedule to the wholesale power contracts. The formulary rate provides for the pass-through of our (i) fixed costs (net of any income from other sources) plus a targeted margin as capacity revenues and (ii) variable costs as energy revenues from our members. Power purchase and sale agreements between us and non-members obligate each non-member to pay us for capacity, if any, and energy furnished in accordance with the prices mutually agreed upon. Margins produced from non-member sales are included in our rate schedule formula and reduce revenue requirements from our members. The consideration we receive for providing capacity services is determined by our formulary rate on an annual basis. The components of the formulary rate associated with capacity costs include the annual budget of fixed costs, a targeted margin and income from other sources. Capacity revenues, therefore, vary to the extent these components vary. Fixed costs include items such as fixed operation and maintenance expenses, administrative and general expenses, depreciation and interest. Year to year, capacity revenue fluctuations are generally due to the recovery of fixed operation and maintenance costs. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. For information regarding regulatory accounting, see Note J. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are 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. For additional information regarding our member prepayment program, see Note K. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members’ service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members’ decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. We provide approximately 60% 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 2019, our board has approved a targeted margins for interest ratio of 1.14. Historically, our board of directors has approved adjustments to revenue requirements by year end such that revenue in excess of that required to meet the targeted margins for interest ratio is refunded to the members. Given that our capacity revenues are based upon budgeted expenditures and generally recognized and billed to our members in equal monthly installments over the course of the year, we may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period we assess our projected revenue requirements through year end to determine whether a refund to our members of excess consideration is likely. If so, we reduce our capacity revenues and recognize a refund liability to our members. Refund liabilities, if any, are included in accounts payable on our consolidated balance sheets. As of September 30, 2019 and September 30, 2018, we recognized refund liabilities totaling $7,700,000 and $20,000,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members for the three and nine months ended September 30, 2019 and 2018 were as follows: Three Months Ended Nine Months Ended September 30, September 30, (dollars in thousands) 2019 2018 2019 2018 Capacity revenues $ 231,270 $ 219,597 $ 712,305 $ 691,649 Energy revenues 151,278 164,932 385,449 432,092 Total $ 382,548 $ 384,529 $ 1,097,754 $ 1,123,741 Member energy requirements supplied % % % % Sales to non-members during the three and nine months ended September 30, 2019 and 2018 were insignificant. Electric capacity and energy revenues are recognized by us without any obligation for returns, warranties or taxes collected. As our members are jointly and severally obligated to pay all expenses associated with owning and operating our power supply business and we perform an on-going assessment of the credit worthiness of non-members, we have not recorded an allowance for doubtful accounts associated with our receivables from members or non-members. We have a rate management program that allows us to expense and recover interest costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Vogtle Units No. 3 and No. 4 can elect to participate in this program on an annual basis. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under this program, amounts billed to participating members during the nine months ended September 30, 2019 and September 30, 2018 were $12,368,000 and $7,897,000, respectively. The cumulative amount billed since inception of the program totaled $78,685,000. In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the nine months ended September 30, 2019 and September 30, 2018 were $35,069,000 and $10,805,000, respectively. Funds collected through this program are invested and held until applied to members’ bills. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members’ bills. The cumulative amount billed since inception of the program totaled $50,505,000.

Leases

Leases	9 Months Ended
	Sep. 30, 2019
Leases
Leases	(G) Leases. As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. On January 1, 2019, we adopted the new leases standard using the optional transition method to apply the new lease guidance as of January 1, 2019, rather than as of the earliest period presented. In addition, we elected the package of practical expedients permitted under the transition guidance, which among other things, allowed us to carry forward the historical lease classification. We also elected the practical expedient related to land easements, allowing us to carry forward our accounting treatment for land easements on existing agreements. Adoption of the new leases standard resulted in recognition of right-of-use assets and offsetting lease liabilities totaling approximately $6,983,000 for certain operating leases. The adoption of this standard did not materially impact our consolidated financial statements. We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the nine months ended September 30, 2019 and September 30, 2018 was insignificant. Finance Leases Three of our finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: · Renew the leases for a period of not less than one year and not more than five years at fair market value, · Purchase the undivided interest at fair market value, or · Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Amortization of the finance lease right-of-use assets is recorded to depreciation and amortization expense. Operating Leases Our operating leases have terms that extend through October 31, 2023. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through December 31, 2019 with renewal options for two additional twenty-year terms. We intend to exercise the option for one additional twenty-year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we used our incremental borrowing rate based on the information available on January 1, 2019, the date of adoption of the new leases standard, in determining the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. September 30, December 31, Classification 2019 2018 (dollars in thousands) Right-of-Use Assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (256,186) (252,233) Total finance lease assets $ 46,546 $ 50,499 Lease liabilities - Finance leases Obligations under finance leases $ 78,771 $ 81,730 Long-term debt and finance leases due within one year 5,763 5,462 Total finance lease liabilities $ 84,534 $ 87,192 September 30, December 31, Classification 2019 2018 (dollars in thousands) Right-of-Use Assets - Operating leases Electric plant in service $ 4,068 $ — Total operating lease assets $ 4,068 $ — Lease liabilities - Operating leases Capitalization - Other $ 2,448 $ — Other current liabilities 2,115 — Total operating lease liabilities $ 4,563 $ — Three months ended Nine months ended September 30, September 30, September 30, September 30, Lease Cost Classification 2019 2018 2019 2018 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,189 $ 1,050 $ 3,567 $ 3,149 Interest on lease liabilities Interest expense 2,372 2,512 7,116 7,534 Operating lease cost: Inventory (1) & production expense 542 1,229 2,308 3,689 Total leased cost $ 4,103 $ 4,791 $ 12,991 $ 14,372 (1) The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil inventories and are recognized in fuel expense as the inventories are consumed. September 30, December 31, 2019 2018 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 9.82 Operating leases N/A Weighted-average discount rate Finance leases 11.05 % 11.05 % Operating leases 4.94 % N/A Nine months ended September 30, September 30, 2019 2018 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,817 $ 10,302 Operating cash flows from operating leases $ 2,602 $ — Financing cash flows from finance leases $ 2,658 $ 4,647 Right-of-use assets obtained in exchange for new operating lease liabilities $ 6,983 $ — Maturity analysis of our finance and operating lease liabilities as of September 30, 2019 is a follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2019 $ 7,475 $ 1,109 $ 8,584 2020 14,949 1,402 16,351 2021 14,949 798 15,747 2022 14,949 608 15,557 2023 14,949 386 15,335 Thereafter 70,481 1,157 71,638 Total lease payments $ 137,752 $ 5,460 $ 143,212 Less: imputed interest (53,218) (897) (54,115) Present value of lease liabilities $ 84,534 $ 4,563 $ 89,097 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and nine months ended September 30, 2019 and September 30, 2018 was as follows: Three months ended Nine months ended September 30, September 30, 2019 2018 2019 2018 (dollars in thousands) Lease income $ 1,514 $ 1,461 $ 4,554 $ 4,406

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	9 Months Ended
	Sep. 30, 2019
Contingencies and Regulatory Matters
Contingencies and Regulatory Matters	(H) Contingencies and Regulatory Matters. We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined. Environmental Matters. As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any 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	9 Months Ended
	Sep. 30, 2019
Restricted Investments
Restricted Investments	(I) Restricted Investments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit currently earn interest at a rate of 5% per annum. Beginning October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At September 30, 2019 and December 31, 2018, we had restricted investments totaling $563,983,000 and $653,158,000, respectively, of which $513,193,000 and $503,158,000, respectively, were classified as long-term.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2019
Regulatory Assets and Liabilities
Regulatory Assets and Liabilities	(J) Regulatory Assets and Liabilities. We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members . The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members. The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of September 30, 2019 and December 31, 2018. 2019 2018 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt (a) $ 41,580 $ 46,315 Amortization of financing leases (b) 35,304 34,918 Outage costs (c) 36,272 36,352 Asset retirement obligations - Ashpond and other (k) 258,227 137,835 Asset retirement obligations - Nuclear (k) — 7,031 Depreciation expense (d) 40,176 41,244 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) 52,802 51,549 Interest rate options cost (f) 120,685 116,960 Deferral of effects on net margin - Smith Energy Facility (g) 156,051 160,509 Other regulatory assets (m) 32,683 22,350 Total Regulatory Assets $ 773,780 $ 655,063 Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ 14,092 $ 13,873 Deferral of effects on net margin - Hawk Road Energy Facility (g) 18,639 19,101 Major maintenance reserve (i) 46,907 45,547 Amortization of financing leases (b) 14,981 17,156 Deferred debt service adder (j) 112,144 105,192 Asset retirement obligations - Nuclear (k) 37,879 — Revenue deferral plan (l) 52,003 15,670 Other regulatory liabilities (m) 2,882 2,459 Total Regulatory Liabilities $ 299,527 $ 218,998 Net Regulatory Assets $ 474,253 $ 436,065 (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 25 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 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 Units No. 1 and No. 2, we deferred the difference between the units’ 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 consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No.3 and No.4. Amortization will commence in February 2020 and continue 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 the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes , as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (l) Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period. (m) The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years.

Member Power Bill Prepayments

Member Power Bill Prepayments	9 Months Ended
	Sep. 30, 2019
Member Power Bill Prepayments
Member Power Bill Prepayments	(K) Member Power Bill Prepayments. We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members’ power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members’ power bills through September 2024, with the majority of the balance scheduled to be credited by the end of 2019.

Debt

Debt	9 Months Ended
	Sep. 30, 2019
Debt
Debt	(L) Debt. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). Following the bankruptcy of Westinghouse in 2017 (as described in Note M), we and the Department of Energy amended the loan guarantee agreement to restrict further advances pending the satisfaction of certain conditions, including an amendment to the loan guarantee agreement. In September 2017, the Department of Energy issued a conditional commitment to us to guarantee an additional $1,619,679,706 of funding from the Federal Financing Bank. On March 7, 2019, we entered into an amendment and waiver of the loan guarantee agreement under which we received an advance of $585,000,000. On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167 and permits us to draw the remaining amount under the Original FFB Notes. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a multi-advance term loan facility (the Facility) under which we may make long-term loan borrowings through the Federal Financing Bank. Proceeds of advances made under the Facility 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 (Eligible Project Costs). Borrowings under the Original FFB Notes may not exceed $3,057,069,461, of which $335,471,604 is designated for capitalized interest. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in December 2017. Total borrowings under the Facility will not exceed $4,676,749,167. At September 30, 2019, aggregate Department of Energy-guaranteed borrowings, including capitalized interest totaled $2,435,490,000. We have no amounts outstanding under the Additional FFB Note. Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event it is required to make any payments to the Federal Financing Bank under its guarantee. Our payment obligations to the Federal Financing Bank under the FFB Notes and reimbursement obligations to the Department of Energy under its guarantee, but not our covenants to the Department of Energy under the Loan Guarantee Agreement, are secured equally and ratably with all of our other obligations issued under our first mortgage indenture. The final maturity date for each advance is February 20, 2044. Interest is payable quarterly in arrears and principal payments on all advances under the FFB Notes will begin on February 20, 2020. Interest rates on advances during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%. Advances under the Original FFB Notes may be requested on a quarterly basis through December 31, 2020. Advances under the Additional FFB Note may be requested on a quarterly basis through November 30, 2023, one year beyond the current anticipated commercial operation date of Vogtle Unit No. 4. Future advances under the Facility are subject to satisfaction of customary conditions, as well as (i) certification of compliance with the requirements of the Title XVII loan guarantee program, (ii) accuracy of project-related representations and warranties, (iii) delivery of updated project-related information, (iv) no Project Adverse Event (as described in Note M) having occurred or, if a Project Adverse Event has occurred, that Co-owners (as described in Note M) representing at least 90% of the ownership interests have voted to continue construction, have not deferred construction and we have provided the Department of Energy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, (vi) evidence of compliance with the applicable wage requirements of the Davis-Bacon Act, as amended, (vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement. We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed. Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default. If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option the Federal Financing Bank's commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners’ termination of such agreement with the intent to replace it, (vii) the Department of Energy’s takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (xii) change of control of Oglethorpe and (xiii) 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. b) Rural Utilities Service Guaranteed Loans: For the nine-month period ended September 30, 2019, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $98,008,000 for long-term financing of general and environmental improvements at existing plants. In October 2019, we received an additional $17,344,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

Vogtle Units No. 3 and No. 4 Co

Vogtle Units No. 3 and No. 4 Construction Project	9 Months Ended
	Sep. 30, 2019
Vogtle Units No. 3 and No. 4 Construction Project
Vogtle Units No. 3 and No. 4 Construction Project	(M) Vogtle Units No. 3 and No. 4 Construction Project. We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our 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. As of September 30, 2019, our total investment in the additional Vogtle units was approximately $4,621,837,000. In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement. In March 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. Effective in July 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement (the Services Agreement), pursuant to which Westinghouse is providing facility design and engineering services, procurement and technical support and staff augmentation on a time and materials cost basis. The Services Agreement provides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days’ written notice. In October 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, pursuant to which Bechtel serves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). 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. In April 2019, Georgia Power and Southern Nuclear completed a cost and schedule validation process to verify and update quantities of commodities remaining to install, labor hours to install remaining quantities and related productivity, testing and system turnover requirements, and forecasted staffing needs and related costs. This process confirmed the total estimated project capital cost forecast for Vogtle Units No. 3 and No. 4. Accordingly, we did not change our $7.5 billion project budget, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency. There was also no change to the in-service dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4 previously approved by the Georgia Public Service Commission following the validation process. The current project-level budget includes an $800 million construction contingency estimate, of which our 30% interest is $240 million. As of September 30, 2019, approximately $67 million of this project-level contingency, or $20 million for our 30% interest, was allocated to the base capital cost forecast for cost risks including, among other factors, attracting and retaining craft labor; adding resources for supervision, field support, project management, initial test program and start-up; and procurement. Georgia Power has stated that it anticipates allocating the remainder of this project-level contingency. The project-level contingency is separate and in addition to our Oglethorpe-level contingency. As construction continues and testing and system turnover activities increase, risks remain that challenges with management of contractors, subcontractors and vendors; supervision of craft labor and related craft labor productivity, particularly in the installation of electric and mechanical commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly and/or installation and the initial testing and start-up, including any required engineering changes, of plant systems, structures or components or regional transmission upgrades, any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost. The April 2019 cost and schedule validation process established target values for monthly construction production and system turnover activities as part of a strategy to maintain margin to the approved in-service dates. To support that strategy, monthly production and activity targets will continue to increase significantly throughout the remainder of 2019 and into 2020. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers, particularly electrical and pipefitter craft labor, as well as additional supervision and other field support resources, must be retained and deployed. 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 submittal by Southern Nuclear of the inspections, tests, analyses, and acceptance criteria documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support authorization to load fuel, 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 Co-owners’ joint ownership agreements, as amended, provide that the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Joint Ownership Agreement provisions described above and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule (each, a Project Adverse Event). The ultimate outcome of these matters cannot be determined at this time. See Note 8 in Item 8—Notes to Audited Consolidated Financial Statements in our 2018 Form 10-K for additional information about Vogtle Units No. 3 and No. 4.

Fair Value (Tables)

Fair Value (Tables)	9 Months Ended
	Sep. 30, 2019
Fair Value
Schedule of assets and liabilities measured at fair value on a recurring basis	Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs September 30, 2019 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 164,319 $ 164,319 $ — $ — International equity trust 88,037 — 88,037 — Corporate bonds and debt 62,039 — 62,039 — US Treasury securities 53,744 53,744 — — Mortgage backed securities 54,803 — 54,803 — Domestic mutual funds 50,990 50,990 — — Municipal bonds 1,237 — 1,237 — Federal agency securities 2,197 — 2,197 — Non-US Gov't bonds & private placements 272 — 272 — Other 5,597 5,597 — — Long-term investments: International equity trust 21,190 — 21,190 — Corporate bonds and debt 18,340 — 18,340 — US Treasury securities 9,772 9,772 — — Mortgage backed securities 13,246 — 13,246 — Domestic mutual funds 94,772 94,772 — — Federal agency securities 46 — 46 — Treasury STRIPS 48,058 — 48,058 — Other 2,600 2,600 — — Natural gas swaps 26,379 — 26,379 — Fair Value Measurements at Reporting Date Using Quoted Prices in Significant Other Significant Active Markets for Observable Unobservable Identical Assets Inputs Inputs December 31, 2018 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 136,196 $ 136,196 $ — $ — International equity trust 76,852 — 76,852 — Corporate bonds and debt 51,356 — 48,853 2,503 US Treasury securities 47,712 47,712 — — Mortgage backed securities 56,004 — 56,004 — Domestic mutual funds 43,359 43,359 — — Municipal bonds 278 — 278 — Federal agency securities 6,066 — 6,066 — Non-US Gov't bonds & private placements 964 — 964 — Other 2,031 2,031 — — Long-term investments: International equity trust 17,382 — 17,382 — Corporate bonds and debt 12,571 — 11,366 1,205 US Treasury securities 12,062 12,062 — — Mortgage backed securities 11,517 — 11,517 — Domestic mutual funds 94,494 94,494 — — Federal agency securities 941 — 941 — Treasury STRIPS 14,113 — 14,113 — Other 1,045 1,045 — — Natural gas swaps 13,154 — 13,154 —
Schedule of changes in Level 3 assets measured at fair value on a recurring basis	Three Months Ended September 30, 2019 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at June 30, 2019 $ — Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) — Liquidations — Balance at September 30, 2019 $ — Nine Months Ended September 30, 2019 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at December 31, 2018 $ 3,708 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) 94 Liquidations (3,802) Balance at September 30, 2019 $ — Three Months Ended September 30, 2018 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at June 30, 2018 $ 4,997 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) (656) Balance at September 30, 2018 $ 4,341 Nine Months Ended September 30, 2018 Corporate bonds and debt (dollars in thousands) Assets (Liabilities): Balance at December 31, 2017 $ — Transfers to Level 3 4,997 Total gains or losses (realized/unrealized): Included in earnings (or changes in net assets) (656) Balance at September 30, 2018 $ 4,341
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 September 30, 2019 and December 31, 2018 were as follows (in thousands): 2019 2018 Carrying Value Fair Value Carrying Value Fair Value Long-term debt $ $ $ 9,347,307 $ 9,837,254

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2019
Derivative Instruments
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year	The following table reflects the notional volume of our natural gas derivatives as of September 30, 2019 that is expected to settle or mature each year: Natural Gas Swaps (MMBTUs) Year (in millions) 2019 3.5 2020 24.9 2021 22.0 2022 15.3 2023 10.2 2024 7.2 Total 83.1
Schedule of fair value of derivative instruments and effect on consolidated balance sheets	Balance Sheet Location Fair Value 2019 2018 (dollars in thousands) Assets: Natural gas swaps Other current assets $ — $ 226 Liabilities: Natural gas swaps Other current liabilities $ 10,435 $ 2,066 Natural gas swaps Other deferred credits $ 15,944 $ 11,314
Schedule of the realized gains and (losses) on derivative instruments recognized in margin	Statement of Three months Nine months Revenues and ended ended Expenses September 30, September 30, Location 2019 2018 2019 2018 (dollars in thousands) Natural Gas Swaps gains Fuel $ — $ 863 $ 224 $ 2,614 Natural Gas Swaps losses Fuel (6,294) (97) (8,093) (956) Total $ (6,294) $ 766 $ (7,869) $ 1,658
Schedule of unrealized losses on derivative instruments deferred on the balance sheet	Balance Sheet Location 2019 2018 (dollars in thousands) Natural gas swaps Regulatory asset $ 26,379 $ 13,154 Total $ 26,379 $ 13,154

Investments in Debt and Equit_2

Investments in Debt and Equity Securities (Tables)	9 Months Ended
	Sep. 30, 2019
Investments in Debt and Equity Securities
Summary of debt and equity securities	Gross Unrealized (dollars in thousands) Fair September 30, 2019 Cost Gains Losses Value Equity $ 256,835 $ 114,881 $ (7,298) $ 364,418 Debt 309,021 10,185 (563) 318,643 Other 8,198 — — 8,198 Total $ 574,054 $ 125,066 $ (7,861) $ 691,259 Gross Unrealized (dollars in thousands) Fair December 31, 2018 Cost Gains Losses Value Equity $ 251,226 $ 64,954 $ (9,105) $ 307,075 Debt 278,030 1,718 (4,955) 274,793 Other 3,075 — — 3,075 Total $ 532,331 $ 66,672 $ (14,060) $ 584,943

Revenue Recognition (Tables)

Revenue Recognition (Tables)	9 Months Ended
	Sep. 30, 2019
Revenue Recognition
Schedule of sales to members	Three Months Ended Nine Months Ended September 30, September 30, (dollars in thousands) 2019 2018 2019 2018 Capacity revenues $ 231,270 $ 219,597 $ 712,305 $ 691,649 Energy revenues 151,278 164,932 385,449 432,092 Total $ 382,548 $ 384,529 $ 1,097,754 $ 1,123,741 Member energy requirements supplied % % % %

Leases (Tables)

Leases (Tables)	9 Months Ended
	Sep. 30, 2019
Leases
Schedule of balance sheet impact of leases	September 30, December 31, Classification 2019 2018 (dollars in thousands) Right-of-Use Assets - Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (256,186) (252,233) Total finance lease assets $ 46,546 $ 50,499 Lease liabilities - Finance leases Obligations under finance leases $ 78,771 $ 81,730 Long-term debt and finance leases due within one year 5,763 5,462 Total finance lease liabilities $ 84,534 $ 87,192 September 30, December 31, Classification 2019 2018 (dollars in thousands) Right-of-Use Assets - Operating leases Electric plant in service $ 4,068 $ — Total operating lease assets $ 4,068 $ — Lease liabilities - Operating leases Capitalization - Other $ 2,448 $ — Other current liabilities 2,115 — Total operating lease liabilities $ 4,563 $ —
Schedule of lease cost	Three months ended Nine months ended September 30, September 30, September 30, September 30, Lease Cost Classification 2019 2018 2019 2018 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,189 $ 1,050 $ 3,567 $ 3,149 Interest on lease liabilities Interest expense 2,372 2,512 7,116 7,534 Operating lease cost: Inventory (1) & production expense 542 1,229 2,308 3,689 Total leased cost $ 4,103 $ 4,791 $ 12,991 $ 14,372 (1) The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil inventories and are recognized in fuel expense as the inventories are consumed.
Summary of lease terms and discount rates	September 30, December 31, 2019 2018 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 9.82 Operating leases N/A Weighted-average discount rate Finance leases 11.05 % 11.05 % Operating leases 4.94 % N/A
Schedule of cash paid for amounts included in the measurement of lease liabilities	Nine months ended September 30, September 30, 2019 2018 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,817 $ 10,302 Operating cash flows from operating leases $ 2,602 $ — Financing cash flows from finance leases $ 2,658 $ 4,647 Right-of-use assets obtained in exchange for new operating lease liabilities $ 6,983 $ —
Schedule of maturities of finance and operating lease liabilities	Maturity analysis of our finance and operating lease liabilities as of September 30, 2019 is a follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2019 $ 7,475 $ 1,109 $ 8,584 2020 14,949 1,402 16,351 2021 14,949 798 15,747 2022 14,949 608 15,557 2023 14,949 386 15,335 Thereafter 70,481 1,157 71,638 Total lease payments $ 137,752 $ 5,460 $ 143,212 Less: imputed interest (53,218) (897) (54,115) Present value of lease liabilities $ 84,534 $ 4,563 $ 89,097
Schedule of lessor's income from leases	Three months ended Nine months ended September 30, September 30, 2019 2018 2019 2018 (dollars in thousands) Lease income $ 1,514 $ 1,461 $ 4,554 $ 4,406

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2019
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 September 30, 2019 and December 31, 2018. 2019 2018 (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt (a) $ 41,580 $ 46,315 Amortization of financing leases (b) 35,304 34,918 Outage costs (c) 36,272 36,352 Asset retirement obligations - Ashpond and other (k) 258,227 137,835 Asset retirement obligations - Nuclear (k) — 7,031 Depreciation expense (d) 40,176 41,244 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs (e) 52,802 51,549 Interest rate options cost (f) 120,685 116,960 Deferral of effects on net margin - Smith Energy Facility (g) 156,051 160,509 Other regulatory assets (m) 32,683 22,350 Total Regulatory Assets $ 773,780 $ 655,063 Regulatory Liabilities: Accumulated retirement costs for other obligations (h) $ 14,092 $ 13,873 Deferral of effects on net margin - Hawk Road Energy Facility (g) 18,639 19,101 Major maintenance reserve (i) 46,907 45,547 Amortization of financing leases (b) 14,981 17,156 Deferred debt service adder (j) 112,144 105,192 Asset retirement obligations - Nuclear (k) 37,879 — Revenue deferral plan (l) 52,003 15,670 Other regulatory liabilities (m) 2,882 2,459 Total Regulatory Liabilities $ 299,527 $ 218,998 Net Regulatory Assets $ 474,253 $ 436,065 (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 25 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 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 Units No. 1 and No. 2, we deferred the difference between the units’ 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 consist of training related costs, including interest and carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units. (f) Deferral of premiums paid to purchase interest rate options used to hedge interest rates on certain borrowings, related carrying costs and other incidentals associated with construction of Vogtle Units No.3 and No.4. Amortization will commence in February 2020 and continue 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 the difference in the timing of recognition of decommissioning costs for financial statement purposes versus ratemaking purposes , as well as the deferral of unrealized gains and losses of funds set aside for decommissioning. (l) Deferred revenues under a rate management program that allows for additional collections over a five-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period. (m) The amortization periods for other regulatory assets range up to 31 years and the amortization periods of other regulatory liabilities range up to 8 years.

General (Details)

General (Details)	9 Months Ended
	Sep. 30, 2019item
General
Number of electric distribution cooperative members	38

Fair Value - Asset and liabilit

Fair Value - Asset and liabilities measured at fair value on a recurring basis (Details) - USD ($)	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Fair value
Nuclear decommissioning trust fund	$ 483,235,000	$ 420,818,000
Long-term investments	208,024,000	164,125,000
Natural gas swaps
Fair value
Derivative liabilities	26,379,000	13,154,000
International equity trust
Fair value
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Natural gas swaps
Fair value
Derivative liabilities	$ 26,379,000	13,154,000
Recurring basis | Domestic equity
Fair value
Nuclear decommissioning trust fund	164,319,000	136,196,000
Recurring basis | International equity trust
Fair value
Nuclear decommissioning trust fund	88,037,000	76,852,000
Long-term investments	21,190,000	17,382,000
Recurring basis | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	62,039,000	51,356,000
Long-term investments	18,340,000	12,571,000
Recurring basis | US Treasury securities
Fair value
Nuclear decommissioning trust fund	53,744,000	47,712,000
Long-term investments	9,772,000	12,062,000
Recurring basis | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	54,803,000	56,004,000
Long-term investments	13,246,000	11,517,000
Recurring basis | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	50,990,000	43,359,000
Long-term investments	94,772,000	94,494,000
Recurring basis | Municipal bonds
Fair value
Nuclear decommissioning trust fund	1,237,000	278,000
Recurring basis | Federal agency securities
Fair value
Nuclear decommissioning trust fund	2,197,000	6,066,000
Long-term investments	46,000	941,000
Recurring basis | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	272,000	964,000
Recurring basis | Treasury STRIPS
Fair value
Long-term investments	48,058,000	14,113,000
Recurring basis | Other
Fair value
Nuclear decommissioning trust fund	5,597,000	2,031,000
Long-term investments	2,600,000	1,045,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value
Nuclear decommissioning trust fund	164,319,000	136,196,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	53,744,000	47,712,000
Long-term investments	9,772,000	12,062,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	50,990,000	43,359,000
Long-term investments	94,772,000	94,494,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value
Nuclear decommissioning trust fund	5,597,000	2,031,000
Long-term investments	2,600,000	1,045,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value
Derivative liabilities	26,379,000	13,154,000
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value
Nuclear decommissioning trust fund	88,037,000	76,852,000
Long-term investments	21,190,000	17,382,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	62,039,000	48,853,000
Long-term investments	18,340,000	11,366,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	54,803,000	56,004,000
Long-term investments	13,246,000	11,517,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	1,237,000	278,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	2,197,000	6,066,000
Long-term investments	46,000	941,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	272,000	964,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS
Fair value
Long-term investments	$ 48,058,000	14,113,000
Recurring basis | Significant Unobservable Inputs (Level 3) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund		2,503,000
Long-term investments		$ 1,205,000

Fair Value - Changes in Level 3

Fair Value - Changes in Level 3 assets (Details) - Significant Unobservable Inputs (Level 3) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018
Changes in Level 3 assets and liabilities measured at fair value on a recurring basis
Balance at the beginning of the period	$ 4,997	$ 3,708	$ 0
Transfers to Level 3			4,997
Total gains or losses (realized/unrealized)
Included in earnings (or changes in net assets)	(656)	94	(656)
Liquidations		(3,802)
Balance at the end of the period	$ 4,341	$ 0	$ 4,341

Fair Value - Estimated fair val

Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Carrying Value
Fair Value
Long-term debt	$ 9,174,752	$ 9,347,307
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value
Long-term debt	$ 10,976,451	$ 9,837,254

Derivative Instruments - Gas he

Derivative Instruments - Gas hedges (Details) - Natural gas swaps MMBTU in Millions	9 Months Ended
	Sep. 30, 2019USD ($)MMBTU	Dec. 31, 2018USD ($)
Derivative Instruments
Derivative liabilities | $	$ 26,379,000	$ 13,154,000
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 | $	$ 26,379,000
Notional volume of natural gas derivatives (in MMBTUs)	83.1
2019
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	3.5
2020
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	24.9
2021
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	22
2022
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	15.3
2023
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	10.2
2024
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	7.2

Derivative Instruments - Fair v

Derivative Instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($)	Sep. 30, 2019	Dec. 31, 2018
Liabilities:
Fair value of liabilities	$ 26,379,000	$ 13,154,000
Other current assets
Assets:
Fair value of assets		226,000
Other current liabilities
Liabilities:
Fair value of liabilities	10,435,000	2,066,000
Other deferred credits
Liabilities:
Fair value of liabilities	$ 15,944,000	$ 11,314,000

Derivative Instruments - Realiz

Derivative Instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			$ 26,379		$ 13,154
Natural gas swaps | Regulatory asset
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			26,379		$ 13,154
Natural gas swaps | Fuel
Gains and (losses) on derivative instruments
Gains		$ 863	224	$ 2,614
Losses	$ (6,294)	(97)	(8,093)	(956)
Total	$ (6,294)	$ 766	$ (7,869)	$ 1,658

Investments in Debt and Equit_3

Investments in Debt and Equity Securities (Details) - USD ($)	9 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Investments in Debt and Equity Securities
Gross unrealized losses greater than one year	$ 22,298,000	$ 49,975,000
Percent of gross unrealized losses which have been unrealized for greater than one year	78.00%	59.00%
Gross unrealized losses less than one year	$ 35,640,000	$ 148,638,000
Cost
Equity	256,835,000	251,226,000
Debt	309,021,000	278,030,000
Other	8,198,000	3,075,000
Total	574,054,000	532,331,000
Gains
Equity	114,881,000	64,954,000
Debt	10,185,000	1,718,000
Total	125,066,000	66,672,000
Losses
Equity	(7,298,000)	(9,105,000)
Debt	(563,000)	(4,955,000)
Total	(7,861,000)	(14,060,000)
Fair Value
Equity	364,418,000	307,075,000
Debt	318,643,000	274,793,000
Other	8,198,000	3,075,000
Total	$ 691,259,000	$ 584,943,000

Revenue Recognition (Details)

Revenue Recognition (Details)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2019USD ($)item	Sep. 30, 2018USD ($)	Dec. 31, 2019
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
Refund liability	$ 7,700,000	$ 20,000,000	$ 7,700,000	$ 20,000,000
Operating revenues	$ 382,623,000	$ 384,644,000	$ 1,098,083,000	$ 1,124,211,000
Member energy requirements supplied	57.00%	57.00%	56.00%	58.00%
Members
Revenue Recognition
Operating revenues	$ 382,548,000	$ 384,529,000	$ 1,097,754,000	$ 1,123,741,000
Non-Members
Revenue Recognition
Operating revenues	75,000	115,000	329,000	470,000
Capacity revenues | Members
Revenue Recognition
Operating revenues	231,270,000	219,597,000	712,305,000	691,649,000
Energy revenues | Members
Revenue Recognition
Operating revenues	$ 151,278,000	$ 164,932,000	$ 385,449,000	$ 432,092,000

Revenue Recognition - Managemen

Revenue Recognition - Management Program (Details) - USD ($)	9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018
Vogtle Units No. 3 & No. 4
Operating revenues
Amounts billed under rate management program	$ 12,368,000	$ 7,897,000
Cumulative recovery of financing costs	78,685,000
Vogtle New Units
Operating revenues
Amounts billed under additional rate management program	35,069,000	$ 10,805,000
Cumulative recovery of financing costs	$ 50,505,000

Leases - Summary (Details)

Leases - Summary (Details)	9 Months Ended
	Sep. 30, 2019USD ($)lease	Jan. 01, 2019USD ($)
Leases
Election of practical expedients package	true
Right of use assets, operating lease	$ 4,068,000
Operating lease liabilities	$ 4,563,000
Finance lease, option to renew	true
Minimum
Leases
Finance lease renewal term	1 year
Maximum
Leases
Finance lease renewal term	5 years
Lease terms through December 31, 2027
Leases
Number of finance leases | lease	3
Lease terms through June 30, 2031
Leases
Number of finance leases | lease	1
Lease terms through October 31, 2023
Leases
Operating lease, option to renew	true
Lease terms through December 31, 2019
Leases
Operating lease, renewal term	20 years
ASU 2016-02 | Adjustments
Leases
Right of use assets, operating lease		$ 6,983,000
Operating lease liabilities		$ 6,983,000
Scherer Unit No. 2
Leases
Percentage of undivided interest in Scherer Unit No. 2	60.00%

Leases - Balance Sheet Impact (

Leases - Balance Sheet Impact (Details) - USD ($) $ in Thousands	Sep. 30, 2019	Dec. 31, 2018
Right-of-use assets - Finance leases
Right-of-Use Assets	$ 302,732	$ 302,732
Less: Accumulated provision for depreciation	(256,186)	(252,233)
Total finance lease assets	46,546	50,499
Lease liabilities - Finance leases
Obligations under finance leases	78,771	81,730
Long-term debt and finance leases due within one year	$ 5,763	$ 5,462
Finance Lease, Liability, Current, Statement of Financial Position	us-gaap:LongTermDebtAndCapitalLeaseObligationsCurrent	us-gaap:LongTermDebtAndCapitalLeaseObligationsCurrent
Total finance lease liabilities	$ 84,534	$ 87,192
Right-of-Use Assets - Operating leases
Electric plant in service	$ 4,068
Right of Use Assets, Operating, Statement of Financial Position	us-gaap:PublicUtilitiesPropertyPlantAndEquipmentPlantInService	us-gaap:PublicUtilitiesPropertyPlantAndEquipmentPlantInService
Total operating lease assets	$ 4,068
Lease liabilities - Operating leases
Capitalization - Other	$ 2,448
Operating Lease, Liability, Noncurrent, Statement of Financial Position	opc:ObligationUnderHydroFacilityTransactions	opc:ObligationUnderHydroFacilityTransactions
Other current liabilities	$ 2,115
Operating Lease, Liability, Current, Statement of Financial Position	us-gaap:OtherLiabilitiesCurrent	us-gaap:OtherLiabilitiesCurrent
Total operating lease liabilities	$ 4,563

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Finance lease cost
Amortization of leased assets	$ 1,189	$ 1,050	$ 3,567	$ 3,149
Interest on lease liabilities	2,372	2,512	7,116	7,534
Operating lease cost	542	1,229	2,308	3,689
Total leased cost	$ 4,103	$ 4,791	$ 12,991	$ 14,372
Weighted-average remaining lease term (in years)
Finance leases	9 years 29 days		9 years 29 days		9 years 9 months 26 days
Operating leases	5 years 8 months 19 days		5 years 8 months 19 days
Weighted-average discount rate
Finance leases	11.05%		11.05%		11.05%
Operating leases	4.94%		4.94%

Leases - Other Lease Disclosure

Leases - Other Lease Disclosures (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2019	Sep. 30, 2018	Sep. 30, 2019	Sep. 30, 2018	Dec. 31, 2018
Lessee
Operating cash flows from finance leases			$ 4,817	$ 10,302
Operating cash flows from operating leases			2,602
Financing cash flows from finance leases			2,658	4,647
Right-of-use assets obtained in exchange for new operating lease liabilities			6,983
Finance Leases
2019	$ 7,475		7,475
2020	14,949		14,949
2021	14,949		14,949
2022	14,949		14,949
2023	14,949		14,949
Thereafter	70,481		70,481
Total lease payments	137,752		137,752
Less: imputed interest	(53,218)		(53,218)
Total finance lease liabilities	84,534		84,534		$ 87,192
Operating Leases
2019	1,109		1,109
2020	1,402		1,402
2021	798		798
2022	608		608
2023	386		386
Thereafter	1,157		1,157
Total lease payments	5,460		5,460
Less: imputed interest	(897)		(897)
Total operating lease liabilities	4,563		4,563
Total finance and operating lease liabilities
2019	8,584		8,584
2020	16,351		16,351
2021	15,747		15,747
2022	15,557		15,557
2023	15,335		15,335
Thereafter	71,638		71,638
Total lease payments	143,212		143,212
Less: imputed interest	(54,115)		(54,115)
Present value of lease liabilities	89,097		89,097
Lessor
Lease income	$ 1,514	$ 1,461	$ 4,554	$ 4,406

Restricted Investments (Details

Restricted Investments (Details)	Oct. 01, 2020	Sep. 30, 2019USD ($)	Dec. 31, 2018USD ($)
Restricted Investments
Guaranteed interest rate on deposit (as a percent)		0.05
Restricted investments		$ 563,983,000	$ 653,158,000
Restricted investments, long-term		$ 513,193,000	$ 503,158,000
Forecast
Restricted Investments
Guaranteed interest rate on deposit (as a percent)	0.04

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2019	Dec. 31, 2018
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 773,780	$ 655,063
Total Regulatory Liabilities	299,527	218,998
Net Regulatory Assets	474,253	436,065
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	14,092	13,873
Deferral of effects on net margin | Hawk Road Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	18,639	19,101
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	46,907	45,547
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	14,981	17,156
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	112,144	105,192
Asset Retirement Obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	37,879
Revenue deferral plan
Regulatory Assets and Liabilities
Total Regulatory Liabilities	52,003	15,670
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 2,882	2,459
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization Period	8 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 41,580	46,315
Premium and loss on reacquired debt | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	25 years
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 35,304	34,918
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 36,272	36,352
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	$ 258,227	137,835
Asset Retirement Obligations | Nuclear
Regulatory Assets and Liabilities
Total Regulatory Assets		7,031
Depreciation expense
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 40,176	41,244
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 No. 3 & No. 4
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 52,802	51,549
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	120,685	116,960
Deferral of effects on net margin - Smith Energy Facility | Smith Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Assets	156,051	160,509
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 32,683	$ 22,350
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	31 years

Debt - Department of Energy Loa

Debt - Department of Energy Loan Guarantee (Details)	9 Months Ended
	Sep. 30, 2019USD ($)	Sep. 30, 2018USD ($)	Mar. 22, 2019USD ($)	Mar. 07, 2019USD ($)	Dec. 31, 2017USD ($)	Sep. 30, 2017USD ($)	Feb. 20, 2014USD ($)item
Debt
Long-term debt proceeds	$ 683,008,000	$ 280,257,000
Vogtle Units No. 3 & No. 4
Debt
Guarantee Obligations Maximum Exposure Received					$ 1,104,000,000
Loan Guarantee Agreement
Debt
Term of debt	5 years
Period of cessation of construction activities which would result in prepayment of outstanding principal	12 months
Period of failure to fund operation and maintenance expenses which would result in prepayment of outstanding principal	12 months
Long-term debt
Debt
Ownership interests voting required to continue construction (as a percent)	90.00%
Long-term debt | FFB
Debt
Number of future advance promissory notes | item							2
Maximum borrowing capacity	$ 3,057,069,461		$ 4,676,749,167				$ 3,057,069,461
Capitalized interest	335,471,604
Aggregate borrowings including capitalized interest	0			$ 585,000,000
Long-term debt | FFB | Department of Energy guarantee
Debt
Maximum borrowing capacity			$ 1,619,679,706
Aggregate borrowings including capitalized interest	$ 2,435,490,000					$ 1,619,679,706
Long-term debt | FFB | US Treasury Securities, Current Yield
Debt
Spread on variable rate (as a percent)	0.375%

Debt - Rural Utilities Service

Debt - Rural Utilities Service Guaranteed Loans (Details) - USD ($)	1 Months Ended	9 Months Ended
	Oct. 31, 2019	Sep. 30, 2019
Long-term debt | FFB | Rural Utilities Service Guaranteed Loans
Debt
Advances received on loans	$ 17,344,000	$ 98,008,000

Vogtle Units No. 3 and No. 4 _2

Vogtle Units No. 3 and No. 4 Construction Project (Details) - Vogtle Units No. 3 & No. 4	9 Months Ended	12 Months Ended
	Sep. 30, 2019USD ($)item	Dec. 31, 2008itemMW	Apr. 30, 2019USD ($)
Public Utility Property Plant and Equipment
Project budget			$ 7,500,000,000
Current project level budget	$ 800,000,000
Percentage of interest in current project level budget	30.00%
Interest in current project level budget (Value)	$ 240,000,000
Allocated project level contingency	67,000,000
Allocated project level contingency from interest in project level budget	20,000,000
Total investment in additional Vogtle units	$ 4,621,837,000
Ownership participation agreement
Public Utility Property Plant and Equipment
Number of additional nuclear units | item	2
Ownership interest (as a percent)	30.00%
Ownership participation agreement | Occurrence of certain adverse events
Public Utility Property Plant and Equipment
Percentage of costs disallowed for recovery	6.00%
Project extension term	1 year
Ownership participation agreement | Minimum | Occurrence of certain adverse events
Public Utility Property Plant and Equipment
Ownership interests voting required to continue construction (as a percent)	90.00%
EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Public Utility Property Plant and Equipment
Number of nuclear units | item		2
Generating capacity of each nuclear unit | MW		1,100
Services Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Public Utility Property Plant and Equipment
Written notice period for termination of agreement	30 days