Oglethorpe Power 10-Q 12 Aug 20 2020 Q2 Quarterly report Financial data

Cover Page

Cover Page	6 Months Ended
	Jun. 30, 2020shares
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2020
Document Transition Report	false
Entity File Number	333-192954
Entity Registrant Name	OGLETHORPE POWER CORP
Entity Incorporation, State or Country Code	GA
Entity Tax Identification Number	58-1211925
Entity Address, Address Line One	2100 East Exchange Place
Entity Address, City or Town	Tucker
Entity Address, State or Province	GA
Entity Address, Postal Zip Code	30084-5336
City Area Code	770
Local Phone Number	270-7600
Entity Current Reporting Status	No
Entity Interactive Data Current	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding	0
Entity Central Index Key	0000788816
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2

Consolidated Balance Sheets (Un

Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Electric plant:
In service	$ 9,347,733	$ 9,209,983
Right-of-use assets—finance leases	302,732	302,732
Less: Accumulated provision for depreciation	(4,879,826)	(4,833,025)
Net in service	4,770,639	4,679,690
Nuclear fuel, at amortized cost	363,140	359,270
Construction work in progress	5,259,324	4,816,896
Total electric plant	10,393,103	9,855,856
Investments and funds:
Nuclear decommissioning trust fund	509,348	511,339
Investment in associated companies	73,972	73,318
Long-term investments	331,000	254,864
Restricted investments	355,340	461,757
Other	27,194	26,422
Total investments and funds	1,296,854	1,327,700
Current assets:
Cash and cash equivalents	371,854	448,612
Restricted short-term investments	191,599	71,833
Receivables	266,471	166,429
Inventories, at average cost	281,805	277,729
Prepayments and other current assets	27,284	9,862
Total current assets	1,139,013	974,465
Deferred charges:
Regulatory assets	758,503	763,512
Prepayments to Georgia Power	35,279	48,052
Other	20,509	20,528
Total deferred charges	814,291	832,092
Total assets	13,643,261	12,990,113
Capitalization:
Patronage capital and membership fees	1,066,113	1,016,747
Long-term debt	9,765,244	9,403,847
Obligation under finance leases	72,354	75,649
Other	26,563	25,196
Total capitalization	10,930,274	10,521,439
Current liabilities:
Long-term debt and finance leases due within one year	238,061	217,440
Short-term borrowings	475,991	282,370
Accounts payable	128,773	165,049
Accrued interest	64,863	65,895
Member power bill prepayments, current	74,385	77,066
Other current liabilities	79,851	49,443
Total current liabilities	1,061,924	857,263
Deferred credits and other liabilities:
Asset retirement obligations	1,094,202	1,070,640
Member power bill prepayments, non-current	110,646	134,396
Regulatory liabilities	407,255	364,241
Other	38,960	42,134
Total deferred credits and other liabilities	1,651,063	1,611,411
Total equity and liabilities	$ 13,643,261	$ 12,990,113

Consolidated Statements of Reve

Consolidated Statements of Revenues and Expenses (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Operating revenues:
Total operating revenues	$ 330,944	$ 358,860	$ 672,618	$ 715,460
Operating expenses:
Fuel	79,596	111,450	150,752	210,442
Production	93,503	105,584	209,634	208,904
Depreciation and amortization	62,588	60,334	124,612	122,638
Purchased power	16,334	16,635	32,947	32,699
Accretion	13,391	13,145	26,626	23,033
Total operating expenses	265,412	307,148	544,571	597,716
Operating margin	65,532	51,712	128,047	117,744
Other income:
Investment income	11,604	14,250	24,538	30,985
Other	1,892	(886)	3,901	942
Total other income	13,496	13,364	28,439	31,927
Interest charges:
Interest expense	101,243	99,729	203,528	201,177
Allowance for debt funds used during construction	(51,047)	(46,910)	(102,077)	(90,337)
Amortization of debt discount and expense	2,670	2,874	5,669	5,852
Net interest charges	52,866	55,693	107,120	116,692
Net margin	26,162	9,383	49,366	32,979
Members
Operating revenues:
Total operating revenues	330,768	358,736	672,281	715,206
Non-Members
Operating revenues:
Total operating revenues	$ 176	$ 124	$ 337	$ 254

Consolidated Statements of Patr

Consolidated Statements of Patronage Capital and Membership Fees (Unaudited) - USD ($) $ in Thousands	3 Months Ended				6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Mar. 31, 2019	Jun. 30, 2020	Jun. 30, 2019
Increase (Decrease) in Members' Capital
Net margin	$ 26,162		$ 9,383		$ 49,366	$ 32,979
Patronage Capital and Membership Fees
Increase (Decrease) in Members' Capital
Beginning balance	1,039,951	$ 1,016,747	985,882	$ 962,286	1,016,747	962,286
Net margin	26,162	23,204	9,383	23,596
Ending balance	$ 1,066,113	$ 1,039,951	$ 995,265	$ 985,882	$ 1,066,113	$ 995,265

Consolidated Statements of Cash

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Cash flows from operating activities:
Net margin	$ 49,366	$ 32,979
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	189,831	185,318
Accretion cost	26,626	23,033
Amortization of deferred gains	(894)	(894)
Allowance for equity funds used during construction	(251)	(427)
Deferred outage costs	(27,507)	(22,470)
Gain on sale of investments	(11,694)	(2,346)
Regulatory deferral of costs associated with nuclear decommissioning	(5,427)	(12,764)
Other	(1,514)	1,282
Change in operating assets and liabilities:
Receivables	(119,414)	(32,090)
Inventories	(4,003)	(15,246)
Prepayments and other current assets	(17,423)	(4,564)
Accounts payable	(42,619)	(50,361)
Accrued interest	(1,032)	24,601
Accrued taxes	22,469	22,916
Other current liabilities	(15,345)	(26,402)
Member power bill prepayments	(26,431)	(78,297)
Rate management program collections	81,105	23,680
Total adjustments	46,477	34,969
Net cash provided by operating activities	95,843	67,948
Cash flows from investing activities:
Property additions	(659,913)	(581,140)
Activity in nuclear decommissioning trust fund—Purchases	(261,327)	(180,121)
Activity in nuclear decommissioning trust fund - Proceeds	257,176	176,037
Increase (decrease) in restricted investments	(13,349)	21,667
Activity in other long-term investments—Purchases	(180,340)	(100,502)
Activity in other long-term investments - Proceeds	110,335	88,085
Other	11,880	(2,940)
Net cash used in investing activities	(735,538)	(578,914)
Cash flows from financing activities:
Long-term debt proceeds	1,377,089	657,986
Long-term debt payments	(1,000,543)	(391,206)
Increase (decrease) in short-term borrowings, net	193,620	(82,162)
Other	(7,229)	(15,714)
Net cash provided by financing activities	562,937	168,904
Net decrease in cash and cash equivalents	(76,758)	(342,062)
Cash and cash equivalents at beginning of period	448,612	752,618
Cash and cash equivalents at end of period	371,854	410,556
Cash paid for—
Interest (net of amounts capitalized)	101,711	85,512
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	0	4,830
Accrued property additions at end of period	112,213	108,258
Interest paid-in-kind	$ 0	$ 35,549

General

General	6 Months Ended
	Jun. 30, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
General	General. The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the three-month and six-month periods ended June 30, 2020 and 2019. 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.

Fair Value

Fair Value	6 Months Ended
	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Fair Value	Fair Value. Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements. The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows: • Level 1. Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded. • Level 2. Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs. • Level 3. Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. As required by the guidance, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques: 1. Market approach. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs. 2. Income approach. The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. 3. Cost approach. The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence. The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2020 and December 31, 2019. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs June 30, 2020 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 162,846 $ 162,846 $ — $ — International equity trust 93,046 — 93,046 — Corporate bonds and debt 88,181 — 88,181 — US Treasury securities 41,699 41,699 — — Mortgage backed securities 62,873 — 62,873 — Domestic mutual funds 50,577 50,577 — — Municipal bonds 1,398 — 1,398 — Federal agency securities 1,348 — 1,348 — Non-US Gov't bonds & private placements 1,377 — 1,377 — Other 6,003 6,003 — — Long-term investments: International equity trust 23,044 — 23,044 — Corporate bonds and debt 27,249 — 27,249 — US Treasury securities 6,408 6,408 — — Mortgage backed securities 12,884 — 12,884 — Domestic mutual funds 124,595 124,595 — — Federal agency securities 1,161 — 1,161 — Treasury STRIPS 133,392 — 133,392 — Other 2,267 2,267 — — Natural gas swaps 31,929 — 31,929 — ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2019 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 179,346 $ 179,346 $ — $ — International equity trust 96,204 — 96,204 — Corporate bonds and debt 63,849 — 63,849 — US Treasury securities 45,522 45,522 — — Mortgage backed securities 62,400 — 62,400 — Domestic mutual funds 55,522 55,522 — — Municipal bonds 1,189 — 1,189 — Federal agency securities 2,586 — 2,586 — Other 4,721 4,450 271 — Long-term investments: International equity trust 23,161 — 23,161 — Corporate bonds and debt 20,395 — 20,395 — US Treasury securities 9,257 9,257 — — Mortgage backed securities 12,867 — 12,867 — Domestic mutual funds 126,380 126,380 — — Federal agency securities 1,082 — 1,082 — Treasury STRIPS 59,816 — 59,816 — Other 1,906 1,906 — — Natural gas swaps 32,256 — 32,256 — ​ ​ ​ ​ ​ 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 estimated fair values of our long-term debt, including current maturities at June 30, 2020 and December 31, 2019 were as follows: 2020 2019 Carrying Fair Carrying Fair ​(in thousands) Long-term debt $ 10,105,932 $ 12,893,268 $ 9,726,428 $ 11,180,658 ​ ​ ​ ​ ​ The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from a third party data reporting service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of June 30, 2020 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	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 June 30, 2020, 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 June 30, 2020 and December 31, 2019, the estimated fair values of our natural gas contracts were net liabilities of approximately $31,929,000 and $32,256,000, respectively. As of June 30, 2020 and December 31, 2019, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on June 30, 2020 due to our credit rating being downgraded below investment grade, we would have been required to post collateral or letters of credit of $31,929,000 with our counterparties. The following table reflects the notional volume of our natural gas derivatives as of June 30, 2020 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2020 17.0 2021 25.6 2022 18.3 2023 14.4 2024 13.2 2025 10.2 Total 98.7 The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2020 and December 31, 2019. Balance Sheet Location Fair Value 2020 2019 (dollars in thousands) Assets: Natural gas swaps Other current assets $ — $ — Liabilities: Natural gas swaps Other current liabilities $ 15,359 $ 12,898 Natural gas swaps Other deferred credits $ 16,570 $ 19,358 The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and six months ended June 30, 2020 and 2019. Statement of Three Months Ended Six Months Ended 2020 2019 2020 2019 (dollars in thousands) Natural Gas Swaps gains Fuel $ — $ 11 $ — $ 224 Natural Gas Swaps losses Fuel (7,141) (1,126) (11,593) (1,799) Total $ (7,141) $ (1,115) $ (11,593) $ (1,575) The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at June 30, 2020 and December 31, 2019. Balance Sheet Location 2020 2019 (dollars in thousands) Natural gas swaps Regulatory asset $ 31,929 $ 32,256 Total $ 31,929 $ 32,256

Investments Securities

Investments Securities	6 Months Ended
	Jun. 30, 2020
Investments, Debt and Equity Securities [Abstract]
Investment Securities	Investment Securities. Investment securities we hold are recorded at fair value in the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses of all investment securities. All realized and unrealized gains and losses are determined using the specific identification method. At June 30, 2020, investments with a fair value of $11,271,000 were in an unrealized loss position for greater than one year and represented approximately 68% of our gross unrealized losses, while investments with a fair value of $45,247,000 were in an unrealized loss position for less than one year. At December 31, 2019, investments with a fair value of $22,352,000 were in an unrealized loss position for greater than one year and represented approximately 86% of our gross unrealized losses, while investments with a fair value of $69,567,000 were in an unrealized loss position for less than one year. The following tables summarize debt and equity securities as of June 30, 2020 and December 31, 2019. Gross Unrealized (dollars in thousands) June 30, 2020 Cost Gains Losses Fair Equity $ 256,741 $ 125,801 $ (11,151) $ 371,391 Debt 440,600 21,243 (1,146) 460,697 Other 8,270 — (10) 8,260 Total $ 705,611 $ 147,044 $ (12,307) $ 840,348 Gross Unrealized (dollars in thousands) December 31, 2019 Cost Gains Losses Fair Equity $ 258,870 $ 144,832 $ (5,990) $ 397,712 Debt 354,535 8,474 (874) 362,135 Other 6,356 — — 6,356 Total $ 619,761 $ 153,306 $ (6,864) $ 766,203

Recently Issued or Adopted Acco

Recently Issued or Adopted Accounting Pronouncements	6 Months Ended
	Jun. 30, 2020
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
Recently Issued or Adopted Accounting Pronouncements	Recently Issued or Adopted Accounting Pronouncements. In June 2016, the Financial Accounting Standards Board (FASB) issued "Financial Instruments—Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments." The amendments in this update replaced the current incurred loss impairment methodology with a methodology that reflects expected credit losses. The new credit losses standard was effective for us prospectively for annual reporting periods beginning after December 15, 2019, and interim periods therein. We adopted the amendments in this update as of January 1, 2020. The adoption of the new credit losses standard did not have a material impact on our consolidated financial statements. In August 2018, the FASB issued "Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement." This standard eliminated, added and modified certain disclosure requirements for fair value measurements as part of the FASB's disclosure framework project. Entities are no longer 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 processeses for Level 3 fair value measurements. However, public business entities are 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 were effective for all entities for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2019. An entity was 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. The adoption of the standard did not have a material impact on our consolidated financial statements. In December 2019, the FASB issued “Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes”, as part of its initiative to reduce complexity in the accounting standards. The amendments in the standard remove certain exceptions and also clarify and simplify various aspects of accounting for income taxes. The new standard is effective for us prospectively for annual reporting periods beginning after December 15, 2020, and interim periods therein. Early adoption is permitted, which we are not electing to do. We are currently evaluating the future impact of this standard on our consolidated financial statements, however, we do not anticipate the impact will be significant.

Revenue Recognition

Revenue Recognition	6 Months Ended
	Jun. 30, 2020
Revenue from Contract with Customer [Abstract]
Revenue Recognition	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 expenses. Fixed costs also include certain costs, such as major maintenance costs, which will be recognized as expense in future periods. Recognition of revenues associated with these future expenses is deferred pursuant to Accounting Standards Codification (ASC) 980, Regulated Operations. The regulatory liabilities are amortized to revenue in accordance with the associated revenue deferral plan as the expenses are recognized. For information regarding regulatory accounting, see Note J. Capacity revenues are recognized by us for standing ready to deliver electricity to our customers. Our capacity revenues are based on the associated costs we expect to recover in a given year and are generally recognized and billed to our members in equal monthly installments over the course of the year regardless of whether our generation and purchased power resources are dispatched to produce electricity. Non-member capacity revenues, if any, are typically billed and recognized in equal monthly installments over the term of the contract. We have a power bill prepayment program pursuant to which our members may prepay future capacity costs and receive a discount. As this program provides us with financing, we adjust our capacity revenues by the amount of the discount, which is based on our avoided cost of borrowing. For additional information regarding our member prepayment program, see Note K. We satisfy our performance obligations to deliver energy as energy is delivered to the applicable meter points. We determine the standard selling price for energy we deliver to our members based upon the variable costs incurred to generate or purchase that energy. Fuel expense is the primary variable cost. Energy revenue recognized equals the actual variable expenses incurred in any given accounting period. Our member energy revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, variable operating costs, the availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights, and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers. For the six-month periods ended June 30, 2020 and 2019, we provided approximately 55% and 56% of our members' energy requirements, respectively. The standard selling price for our energy revenues from non-members is the price mutually agreed upon. We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For 2020, 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 June 30, 2020 and June 30, 2019, we recognized refund liabilities totaling $5,850,000 and $4,500,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members. Sales to members for the three and six months ended June 30, 2020 and 2019 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2020 2019 2020 2019 Capacity revenues $ 240,256 $ 235,049 $ 499,649 $ 481,035 Energy revenues 90,512 123,687 172,632 234,171 Total $ 330,768 $ 358,736 $ 672,281 $ 715,206 Member energy requirements supplied 59 % 59 % 55 % 56 % Receivables from contracts with our members at June 30, 2020 and December 31, 2019 were $231,105,000 and $142,946,000, respectively. Sales to non-members during the three and six months ended June 30, 2020 and 2019 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 six months ended June 30, 2020 and June 30, 2019 were $7,893,000 and $8,966,000, respectively. The cumulative amount billed since inception of the program totaled $89,152,000. 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 five

Leases

Leases	6 Months Ended
	Jun. 30, 2020
Leases [Abstract]
Leases	Leases. As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. 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 six months ended June 30, 2020 and June 30, 2019 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through March 16, 2024. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2020 December 31, 2019 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (260,139) (257,504) Total finance lease assets $ 42,593 $ 45,228 Lease liabilities—Finance leases Obligations under finance leases $ 72,354 $ 75,649 Long-term debt and finance leases due within one year 6,418 6,081 Total finance lease liabilities $ 78,772 $ 81,730 Classification June 30, 2020 December 31, 2019 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service $ 3,795 $ 3,237 Total operating lease assets $ 3,795 $ 3,237 Lease liabilities—Operating leases Capitalization—Other $ 2,889 $ 2,293 Other current liabilities 1,001 1,252 Total operating lease liabilities $ 3,890 $ 3,545 Three months ended Six months ended Lease Cost Classification June 30, 2020 June 30, 2019 June 30, 2020 June 30, 2019 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,344 $ 1,189 $ 2,688 $ 2,378 Interest on lease liabilities Interest expense 2,217 2,372 4,434 4,744 Operating lease cost: Inventory (1) & production expense 272 883 795 1,766 Total leased cost $ 3,833 $ 4,444 $ 7,917 $ 8,888 (1) The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. June 30, 2020 December 31, 2019 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 8.59 8.84 Operating leases 7.34 7.39 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.62 % 5.12 % Six months ended June 30, 2020 June 30, 2019 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,516 $ — Operating cash flows from operating leases $ 950 $ 1,840 Financing cash flows from finance leases $ 2,959 $ — Right-of-use assets obtained in exchange for new operating lease liabilities $ 1,227 $ 6,983 Maturity analysis of our finance and operating lease liabilities as of June 30, 2020 is a follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2020 $ 7,475 $ 612 $ 8,087 2021 14,949 1,121 16,070 2022 14,949 930 15,879 2023 14,949 709 15,658 2024 14,949 235 15,184 Thereafter 55,533 1,085 56,618 Total lease payments $ 122,804 $ 4,692 $ 127,496 Less: imputed interest (44,032) (802) (44,834) Present value of lease liabilities $ 78,772 $ 3,890 $ 82,662 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and six months ended June 30, 2020 and June 30, 2019 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 (dollars in thousands) Lease income $ 1,542 $ 1,522 $ 3,090 $ 3,040
Leases	Leases. As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value. 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 six months ended June 30, 2020 and June 30, 2019 was insignificant. Finance Leases Three of our Scherer Unit No. 2 finance leases have lease terms through December 31, 2027, and one lease extends through June 30, 2031. At the end of the leases, we can elect at our sole discretion to: • Renew the leases for a period of not less than one year and not more than five years at fair market value, • Purchase the undivided interest at fair market value, or • Redeliver the undivided interest to the lessors. For rate-making purposes, we include the actual lease payments for our finance leases in our cost of service. The difference between lease payments and the aggregate of the amortization on the right-of-use asset and the interest on the finance lease obligation is recognized as a regulatory asset. Finance lease amortization is recorded in depreciation and amortization expense. Operating Leases Our railcar operating leases have terms that extend through March 16, 2024. At the end of the railcar operating leases, we can renew at terms mutually agreeable by us and the lessors, purchase the assets or return the assets to the lessors. We have an additional operating lease that has a term that extends through February 2042 with one renewal option for a 20 year term. The exercise of renewal options for our finance and operating leases is at our sole discretion. As all of our operating leases do not provide an implicit rate, we use an incremental borrowing rate based on the information available at the time new lease agreements are entered into or reassessed to determine the present value of lease payments. For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2020 December 31, 2019 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (260,139) (257,504) Total finance lease assets $ 42,593 $ 45,228 Lease liabilities—Finance leases Obligations under finance leases $ 72,354 $ 75,649 Long-term debt and finance leases due within one year 6,418 6,081 Total finance lease liabilities $ 78,772 $ 81,730 Classification June 30, 2020 December 31, 2019 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service $ 3,795 $ 3,237 Total operating lease assets $ 3,795 $ 3,237 Lease liabilities—Operating leases Capitalization—Other $ 2,889 $ 2,293 Other current liabilities 1,001 1,252 Total operating lease liabilities $ 3,890 $ 3,545 Three months ended Six months ended Lease Cost Classification June 30, 2020 June 30, 2019 June 30, 2020 June 30, 2019 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,344 $ 1,189 $ 2,688 $ 2,378 Interest on lease liabilities Interest expense 2,217 2,372 4,434 4,744 Operating lease cost: Inventory (1) & production expense 272 883 795 1,766 Total leased cost $ 3,833 $ 4,444 $ 7,917 $ 8,888 (1) The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed. June 30, 2020 December 31, 2019 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 8.59 8.84 Operating leases 7.34 7.39 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.62 % 5.12 % Six months ended June 30, 2020 June 30, 2019 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,516 $ — Operating cash flows from operating leases $ 950 $ 1,840 Financing cash flows from finance leases $ 2,959 $ — Right-of-use assets obtained in exchange for new operating lease liabilities $ 1,227 $ 6,983 Maturity analysis of our finance and operating lease liabilities as of June 30, 2020 is a follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2020 $ 7,475 $ 612 $ 8,087 2021 14,949 1,121 16,070 2022 14,949 930 15,879 2023 14,949 709 15,658 2024 14,949 235 15,184 Thereafter 55,533 1,085 56,618 Total lease payments $ 122,804 $ 4,692 $ 127,496 Less: imputed interest (44,032) (802) (44,834) Present value of lease liabilities $ 78,772 $ 3,890 $ 82,662 As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases. Lease income recognized during the three and six months ended June 30, 2020 and June 30, 2019 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 (dollars in thousands) Lease income $ 1,542 $ 1,522 $ 3,090 $ 3,040

Contingencies and Regulatory Ma

Contingencies and Regulatory Matters	6 Months Ended
	Jun. 30, 2020
Contingencies and Regulatory Matters
Contingencies and Regulatory Matters	Contingencies and Regulatory Matters. We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined. Environmental Matters. As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance. At this time, the ultimate impact of any 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. On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer, of which we are a co-owner, have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. The plaintiffs seek an unspecified amount of monetary damages including punitive damages, a medical monitoring fund, and injunctive relief.

Restricted Investments

Restricted Investments	6 Months Ended
	Jun. 30, 2020
Restricted Investments Note [Abstract]
Restricted Investments	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 June 30, 2020 and December 31, 2019, we had restricted investments totaling $546,939,000 and $533,590,000, respectively, of which $355,340,000 and $461,757,000, respectively, were classified as long-term.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	6 Months Ended
	Jun. 30, 2020
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities. We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members. The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members. The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of June 30, 2020 and December 31, 2019. 2020 2019 ​ (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 37,624 $ 40,067 Amortization of financing leases(b) 35,381 35,433 Outage costs(c) 43,093 34,367 Asset retirement obligations—Ashpond and other(k) 236,834 245,932 Depreciation expense(d) 39,108 39,820 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e) 54,113 53,466 Interest rate options cost(f) 124,444 121,938 Deferral of effects on net margin—Smith Energy Facility(g) 151,592 154,564 Other regulatory assets(m) 36,314 37,925 Total Regulatory Assets $ 758,503 $ 763,512 Regulatory Liabilities: Accumulated retirement costs for other obligations(h) $ 18,343 $ 12,692 Deferral of effects on net margin—Hawk Road Energy Facility(g) 18,177 18,485 Major maintenance reserve(i) 41,768 50,144 Amortization of financing leases(b) 12,806 14,256 Deferred debt service adder(j) 119,115 114,453 Asset retirement obligations—Nuclear(k) 38,711 61,516 Revenue deferral plan(l) 155,117 90,066 Other regulatory liabilities(m) 3,218 2,629 Total Regulatory Liabilities $ 407,255 $ 364,241 Net Regulatory Assets $ 351,248 $ 399,271 (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 24 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle 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 when Vogtle Unit No. 3 goes in-service, which is expected November 2021. (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 five (m) The amortization periods for other regulatory assets range up to 30 years and the amortization periods of other regulatory liabilities range up to 7 years.

Member Power Bill Prepayments

Member Power Bill Prepayments	6 Months Ended
	Jun. 30, 2020
Member Power Bill Prepayments
Member Power Bill Prepayments	Member Power Bill Prepayments. We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through December 2024, with the majority of the balance scheduled to be credited by the end of 2020.

Debt

Debt	6 Months Ended
	Jun. 30, 2020
Debt Disclosure [Abstract]
Debt	Debt. a) Department of Energy Loan Guarantee: Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents). On March 22, 2019, we and the Department of Energy entered into an Amended and Restated Loan Guarantee Agreement (as amended, the Loan Guarantee Agreement) which increased the aggregate amount guaranteed by the Department of Energy to $4,676,749,167. We also entered into a Note Purchase Agreement dated as of March 22, 2019 (the Additional Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and a future advance promissory note, dated March 22, 2019, made by us to the Federal Financing Bank in the amount of $1,619,679,706 (the Additional FFB Note and together with the Additional Note Purchase Agreement, the Additional FFB Documents). Together, the Original FFB Documents and Additional FFB Documents provide for a 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. We have advanced all amounts available under the Original FFB Note. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original FFB Note due to timing of borrowing and lower than expected interest rates. Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in late 2017. At June 30, 2020, borrowings under the Additional FFB Note totaled $444,000,000. At June 30, 2020, aggregate Department of Energy-guaranteed borrowings, including capitalized interest, totaled $3,457,348,000. Total borrowings under the Facility will not exceed $4,633,028,088. 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 began 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 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 twelve b) Rural Utilities Service Guaranteed Loans: For the six-month period ended June 30, 2020, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $40,089,000 for long-term financing of general and environmental improvements at existing plants. In July 2020, we received an additional $5,836,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants. c) Lines of Credit: In mid-March 2020, due to significant disruptions in the commercial paper markets, we began to borrow directly under our $1.2 billion syndicated CFC line of credit in lieu of issuing commercial paper. As of June 30, 2020, we had repaid the borrowings under this line of credit with the proceeds of commercial paper we were able to issue as markets stabilized. On March 27, 2020, we amended our JPMorgan Chase line of credit, increasing the commitment from $150,000,000 to $363,000,000. On March 31, 2020, we borrowed $213,000,000 under this line of credit to purchase $212,760,000 of Series 2013 pollution control bonds that were subject to mandatory tender on April 1, 2020. At June 30, 2020, these borrowings remained outstanding and were classified as long-term debt. On July 30, 2020, we repaid these borrowings from proceeds from commercial paper issuances.

Vogtle Units No. 3 and No. 4 Co

Vogtle Units No. 3 and No. 4 Construction Project	6 Months Ended
	Jun. 30, 2020
Vogtle Units No. 3 and No. 4 Construction Project
Vogtle Units No. 3 and No. 4 Construction Project	Vogtle Units No. 3 and No. 4 Construction Project. We, Georgia Power, the Municipal Electric Authority of Georgia, 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. 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. Our current budget for our 30% ownership interest in Vogtle Units No. 3 and No. 4 is $7.5 billion, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency and is based on November 2021 and November 2022 commercial operation dates, respectively. As of June 30, 2020, our total investment in the additional Vogtle units was approximately $5.5 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation. The Georgia Public Service Commission approved in-service dates for Vogtle Units No. 3 and No. 4 are November 2021 and November 2022, respectively. As part of its ongoing process, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and workforce statistics. The August 2018 project-level budget included an $800 million construction contingency estimate, of which our 30% interest is $240 million. During the second quarter of 2020, approximately $425 million of construction contingency, which our 30% interest was $128 million, was assigned to the base capital cost forecast for cost risks including, among other things, construction productivity, including the April 2020 reduction in workforce designed to mitigate the impacts of the COVID-19 pandemic described below, field support, subcontracts, engineering resources and procurement. When combined with prior assignments of construction contingency, the second quarter 2020 assignment of contingency exceeded the remaining balance of the $800 million contingency by approximately $75 million, of which our 30% interest was $23 million. Through June 30, 2020, assignments of contingency for cost risks also have included, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As a result of these factors, Southern Nuclear established additional construction contingency of $250 million (of which our 30% interest is $75 million) for further potential risks, including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. Georgia Power has stated its expectation to allocate the remainder of this project-level contingency by completion of the project. The project-level contingency is separate and in addition to our Oglethorpe-level contingency. The assignment of project-level contingency through June 30, 2020 and our $75 million share of the additional project-level contingency reduced the amount of our Oglethorpe-level contingency but did not change our current $7.5 billion budget. After taking into account the increase of project-level contingency, our remaining Oglethorpe-level contingency is $325 million. The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, was designed to cover potential cost, schedule, and financing risks associated with our share of the project which may not be covered by project-level contingencies. As construction progresses, the Oglethorpe-level contingency may continue to fluctuate as it represents the difference between known project-level costs and contingencies and our total budget of $7.5 billion. At the end of the project, if there is remaining Oglethorpe-level contingency, we will adjust our project budget to remove this contingency and bill our members based on the actual project costs. The table below shows our project budget and actual costs through June 30, 2020 for our 30% interest in the project. (in millions) Project Budget Actual Costs at June 30, 2020 Remaining Project Budget Construction Costs (1) $ 5,524 $ 4,303 $ 1,221 Financing Costs 1,576 1,151 425 Total Costs $ 7,100 $ 5,454 $ 1,646 Project-Level Contingency $ 75 $ — $ 75 Oglethorpe-Level Contingency 325 — 325 Total Contingency $ 400 $ — $ 400 Totals $ 7,500 $ 5,454 $ 2,046 (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement. In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures. In April 2020, Georgia Power, acting for itself and as agent for the other Co-owners, announced a reduction in workforce at Vogtle Units No. 3 and No. 4, which totaled approximately 20% of the then-existing site workforce. This reduction in workforce was a mitigation action intended to address ongoing challenges with labor productivity that were exacerbated by the impact of the COVID-19 pandemic on the Vogtle Units No. 3 and No. 4 workforce and construction site. The April 2020 workforce reduction was intended to provide operational efficiencies by increasing productivity of the remaining workforce and reducing workforce fatigue and absenteeism. Further, it was also intended to allow for increased social distancing by the workforce and facilitate compliance with the recommendations from the Centers for Disease Control and Prevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the levels anticipated, contributing to the allocation of, and increase in, construction contingency described above. Southern Nuclear and Georgia Power are pursuing an aggressive site work plan as a strategy to achieve completion of the units by their regulatory-approved in-service dates. In July 2020, Southern Nuclear updated its cost and schedule forecast, and indicated that it still expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively. Starting in February 2020, Southern Nuclear also began providing a schedule benchmark that forecasts production levels and adjusts project milestones to align with the regulatory-approved in-service dates. We believe the production levels and timeframes consistent with the assumptions in this benchmark provide reasonable assurance that Units No. 3 and No. 4 will meet the regulatory-approved in-service dates of November 2021 and November 2022, respectively, within our current $7.5 billion budget. As construction, including subcontract work, continues and testing and system turnover activities increase, risks remain that challenges with management of contractors and vendors; subcontractor performance; supervision of craft labor and related productivity, particularly in the installation of electrical, mechanical, and instrumentation and controls commodities, ability to attract and retain craft labor and/or related cost escalation; procurement, fabrication, delivery, assembly, installation, system turnover, and the initial testing and start-up, including any required engineering changes or any remediation related thereto, of plant systems, structures or components (some of which are based on new technology that has only within the last few years began initial operation in the global nuclear industry at this scale), any of which may require additional labor and/or materials; or other issues could arise and further impact the projected schedule and estimated cost. In addition, the continuing effects of the COVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and support activities at Vogtle Units No. 3 and No. 4. The incremental cost associated with COVID-19 mitigation actions and impacts on construction productivity is currently estimated to be between $150 million and $250 million (of which our 30% interest is $45 million to $75 million) and is included in the project budget and assumes (i) absenteeism rates normalize and (ii) the intended productivity efficiencies and production targets are realized in the coming months. The ultimate impact of the COVID-19 pandemic on the construction schedule and budget for Vogtle Units No. 3 and No. 4 cannot be determined at this time. 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 inspections, tests, analyses, and acceptance documentation for each unit and the related reviews and approvals by the Nuclear Regulatory Commission necessary to support Nuclear Regulatory Commission authorization to load fuel, may arise, which may result in additional license amendments or require other resolution. On May 11, 2020, the Blue Ridge Environmental Defense League filed a petition with the Nuclear Regulatory Commission that challenges a license amendment request. On June 15, 2020, the Nuclear Regulatory Commission issued an appealable order rejecting Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain inspections, tests, analyses, and acceptance criteria. 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.

Financial Instruments Credit Lo

Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	6 Months Ended
	Jun. 30, 2020
Accounting Policies [Abstract]
Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments	Financial Instruments Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. On January 1, 2020, we adopted the new credit losses standard issued by the FASB that requires consideration of a broader range of information to estimate expected credit losses over the lifetime of financial assets measured at amortized cost. The new credit losses standard replaced the “incurred loss” methodology for recognizing credit losses that delayed recognition until it was probable a loss had been incurred. The financial assets we hold that are subject to the new standard are predominately accounts receivable and certain cash equivalents classified as held-to-maturity debt (e.g. commercial paper). Our receivables are generally due within thirty days or less with a significant portion related to billings to our members. See Note F for information regarding our member receivables. Commercial paper issuances we invest in are rated as investment grade and backed by a credit facility. Given our historical experience, the short duration lifetime of these financial assets and the short time horizon over which to consider expectations of future economic conditions, we have assessed that non-collection of the cost basis of these financial assets is remote. The adoption of the new credit losses standard did not materially impact our consolidated financial statements.

Fair Value (Tables)

Fair Value (Tables)	6 Months Ended
	Jun. 30, 2020
Fair Value Disclosures [Abstract]
Schedule of assets and liabilities measured at fair value on a recurring basis	The tables below detail assets and liabilities measured at fair value on a recurring basis at June 30, 2020 and December 31, 2019. Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs June 30, 2020 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 162,846 $ 162,846 $ — $ — International equity trust 93,046 — 93,046 — Corporate bonds and debt 88,181 — 88,181 — US Treasury securities 41,699 41,699 — — Mortgage backed securities 62,873 — 62,873 — Domestic mutual funds 50,577 50,577 — — Municipal bonds 1,398 — 1,398 — Federal agency securities 1,348 — 1,348 — Non-US Gov't bonds & private placements 1,377 — 1,377 — Other 6,003 6,003 — — Long-term investments: International equity trust 23,044 — 23,044 — Corporate bonds and debt 27,249 — 27,249 — US Treasury securities 6,408 6,408 — — Mortgage backed securities 12,884 — 12,884 — Domestic mutual funds 124,595 124,595 — — Federal agency securities 1,161 — 1,161 — Treasury STRIPS 133,392 — 133,392 — Other 2,267 2,267 — — Natural gas swaps 31,929 — 31,929 — ​ ​ ​ ​ ​ Fair Value Measurements at Reporting Date Using Quoted Prices in Active Markets for Identical Assets Significant Other Observable Inputs Significant Unobservable Inputs December 31, 2019 (Level 1) (Level 2) (Level 3) (dollars in thousands) Nuclear decommissioning trust funds: Domestic equity $ 179,346 $ 179,346 $ — $ — International equity trust 96,204 — 96,204 — Corporate bonds and debt 63,849 — 63,849 — US Treasury securities 45,522 45,522 — — Mortgage backed securities 62,400 — 62,400 — Domestic mutual funds 55,522 55,522 — — Municipal bonds 1,189 — 1,189 — Federal agency securities 2,586 — 2,586 — Other 4,721 4,450 271 — Long-term investments: International equity trust 23,161 — 23,161 — Corporate bonds and debt 20,395 — 20,395 — US Treasury securities 9,257 9,257 — — Mortgage backed securities 12,867 — 12,867 — Domestic mutual funds 126,380 126,380 — — Federal agency securities 1,082 — 1,082 — Treasury STRIPS 59,816 — 59,816 — Other 1,906 1,906 — — Natural gas swaps 32,256 — 32,256 — ​ ​ ​ ​ ​
Schedule of estimated fair values of long-term debt, including current maturities	The estimated fair values of our long-term debt, including current maturities at June 30, 2020 and December 31, 2019 were as follows: 2020 2019 Carrying Fair Carrying Fair ​(in thousands) Long-term debt $ 10,105,932 $ 12,893,268 $ 9,726,428 $ 11,180,658 ​ ​ ​ ​ ​

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of notional volume of natural gas derivatives that is expected to settle or mature each year	The following table reflects the notional volume of our natural gas derivatives as of June 30, 2020 that is expected to settle or mature each year: Year Natural Gas Swaps (MMBTUs) (in millions) 2020 17.0 2021 25.6 2022 18.3 2023 14.4 2024 13.2 2025 10.2 Total 98.7
Schedule of fair value of derivative instruments and effect on consolidated balance sheets	The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at June 30, 2020 and December 31, 2019. Balance Sheet Location Fair Value 2020 2019 (dollars in thousands) Assets: Natural gas swaps Other current assets $ — $ — Liabilities: Natural gas swaps Other current liabilities $ 15,359 $ 12,898 Natural gas swaps Other deferred credits $ 16,570 $ 19,358
Schedule of the realized gains and (losses) on derivative instruments recognized in margin	The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and six months ended June 30, 2020 and 2019. Statement of Three Months Ended Six Months Ended 2020 2019 2020 2019 (dollars in thousands) Natural Gas Swaps gains Fuel $ — $ 11 $ — $ 224 Natural Gas Swaps losses Fuel (7,141) (1,126) (11,593) (1,799) Total $ (7,141) $ (1,115) $ (11,593) $ (1,575)
Schedule of unrealized losses on derivative instruments deferred on the balance sheet	The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at June 30, 2020 and December 31, 2019. Balance Sheet Location 2020 2019 (dollars in thousands) Natural gas swaps Regulatory asset $ 31,929 $ 32,256 Total $ 31,929 $ 32,256

Investment Securities (Tables)

Investment Securities (Tables)	6 Months Ended
	Jun. 30, 2020
Investments, Debt and Equity Securities [Abstract]
Summary of debt and equity securities	The following tables summarize debt and equity securities as of June 30, 2020 and December 31, 2019. Gross Unrealized (dollars in thousands) June 30, 2020 Cost Gains Losses Fair Equity $ 256,741 $ 125,801 $ (11,151) $ 371,391 Debt 440,600 21,243 (1,146) 460,697 Other 8,270 — (10) 8,260 Total $ 705,611 $ 147,044 $ (12,307) $ 840,348 Gross Unrealized (dollars in thousands) December 31, 2019 Cost Gains Losses Fair Equity $ 258,870 $ 144,832 $ (5,990) $ 397,712 Debt 354,535 8,474 (874) 362,135 Other 6,356 — — 6,356 Total $ 619,761 $ 153,306 $ (6,864) $ 766,203

Revenue Recognition (Tables)

Revenue Recognition (Tables)	6 Months Ended
	Jun. 30, 2020
Revenue from Contract with Customer [Abstract]
Schedule of sales to members	Sales to members for the three and six months ended June 30, 2020 and 2019 were as follows: Three Months Ended Six Months Ended (dollars in thousands) 2020 2019 2020 2019 Capacity revenues $ 240,256 $ 235,049 $ 499,649 $ 481,035 Energy revenues 90,512 123,687 172,632 234,171 Total $ 330,768 $ 358,736 $ 672,281 $ 715,206 Member energy requirements supplied 59 % 59 % 55 % 56 %

Leases (Tables)

Leases (Tables)	6 Months Ended
	Jun. 30, 2020
Leases [Abstract]
Schedule of balance sheet impact of leases	For lease agreements entered into or reassessed after the adoption of the new leases standard, we combine lease and nonlease components. Classification June 30, 2020 December 31, 2019 (dollars in thousands) Right-of-Use Assets—Finance leases Right-of-use assets $ 302,732 $ 302,732 Less: Accumulated provision for depreciation (260,139) (257,504) Total finance lease assets $ 42,593 $ 45,228 Lease liabilities—Finance leases Obligations under finance leases $ 72,354 $ 75,649 Long-term debt and finance leases due within one year 6,418 6,081 Total finance lease liabilities $ 78,772 $ 81,730 Classification June 30, 2020 December 31, 2019 (dollars in thousands) Right-of-Use Assets—Operating leases Electric plant in service $ 3,795 $ 3,237 Total operating lease assets $ 3,795 $ 3,237 Lease liabilities—Operating leases Capitalization—Other $ 2,889 $ 2,293 Other current liabilities 1,001 1,252 Total operating lease liabilities $ 3,890 $ 3,545
Schedule of lease cost	Three months ended Six months ended Lease Cost Classification June 30, 2020 June 30, 2019 June 30, 2020 June 30, 2019 (dollars in thousands) Finance lease cost: Amortization of leased assets Depreciation and amortization $ 1,344 $ 1,189 $ 2,688 $ 2,378 Interest on lease liabilities Interest expense 2,217 2,372 4,434 4,744 Operating lease cost: Inventory (1) & production expense 272 883 795 1,766 Total leased cost $ 3,833 $ 4,444 $ 7,917 $ 8,888 (1) The majority of our operating lease costs relates to our railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the inventories are consumed.
Summary of lease terms and discount rates	June 30, 2020 December 31, 2019 Lease Term and Discount Rate: Weighted-average remaining lease term (in years) Finance leases 8.59 8.84 Operating leases 7.34 7.39 Weighted-average discount rate: Finance leases 11.05 % 11.05 % Operating leases 4.62 % 5.12 %
Schedule of cash paid for amounts included in the measurement of lease liabilities	Six months ended June 30, 2020 June 30, 2019 (dollars in thousands) Other Information: Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from finance leases $ 4,516 $ — Operating cash flows from operating leases $ 950 $ 1,840 Financing cash flows from finance leases $ 2,959 $ — Right-of-use assets obtained in exchange for new operating lease liabilities $ 1,227 $ 6,983
Schedule of maturities of finance and operating lease liabilities	Maturity analysis of our finance and operating lease liabilities as of June 30, 2020 is a follows: (dollars in thousands) Year Ending December 31, Finance Leases Operating Leases Total 2020 $ 7,475 $ 612 $ 8,087 2021 14,949 1,121 16,070 2022 14,949 930 15,879 2023 14,949 709 15,658 2024 14,949 235 15,184 Thereafter 55,533 1,085 56,618 Total lease payments $ 122,804 $ 4,692 $ 127,496 Less: imputed interest (44,032) (802) (44,834) Present value of lease liabilities $ 78,772 $ 3,890 $ 82,662
Schedule of lessor's income from leases	Lease income recognized during the three and six months ended June 30, 2020 and June 30, 2019 was as follows: Three Months Ended June 30, Six Months Ended June 30, 2020 2019 2020 2019 (dollars in thousands) Lease income $ 1,542 $ 1,522 $ 3,090 $ 3,040

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2020
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of regulatory assets and liabilities	The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of June 30, 2020 and December 31, 2019. 2020 2019 ​ (dollars in thousands) Regulatory Assets: Premium and loss on reacquired debt(a) $ 37,624 $ 40,067 Amortization of financing leases(b) 35,381 35,433 Outage costs(c) 43,093 34,367 Asset retirement obligations—Ashpond and other(k) 236,834 245,932 Depreciation expense(d) 39,108 39,820 Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e) 54,113 53,466 Interest rate options cost(f) 124,444 121,938 Deferral of effects on net margin—Smith Energy Facility(g) 151,592 154,564 Other regulatory assets(m) 36,314 37,925 Total Regulatory Assets $ 758,503 $ 763,512 Regulatory Liabilities: Accumulated retirement costs for other obligations(h) $ 18,343 $ 12,692 Deferral of effects on net margin—Hawk Road Energy Facility(g) 18,177 18,485 Major maintenance reserve(i) 41,768 50,144 Amortization of financing leases(b) 12,806 14,256 Deferred debt service adder(j) 119,115 114,453 Asset retirement obligations—Nuclear(k) 38,711 61,516 Revenue deferral plan(l) 155,117 90,066 Other regulatory liabilities(m) 3,218 2,629 Total Regulatory Liabilities $ 407,255 $ 364,241 Net Regulatory Assets $ 351,248 $ 399,271 (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 24 years. (b) Represents the difference between expense recognized for rate-making purposes versus financial statement purposes related to finance lease payments and the aggregate of the amortization of the asset and interest on the obligation. (c) Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 or 24-month operating cycles of each unit. (d) Prior to Nuclear Regulatory Commission (NRC) approval of a 20-year license extension for Plant Vogtle 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 when Vogtle Unit No. 3 goes in-service, which is expected November 2021. (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 five (m) The amortization periods for other regulatory assets range up to 30 years and the amortization periods of other regulatory liabilities range up to 7 years.

Vogtle Units No. 3 and No. 4 _2

Vogtle Units No. 3 and No. 4 Construction Project (Tables)	6 Months Ended
	Jun. 30, 2020
Vogtle Units No. 3 and No. 4 Construction Project
Schedule of Project Budget and Actual Costs	The table below shows our project budget and actual costs through June 30, 2020 for our 30% interest in the project. (in millions) Project Budget Actual Costs at June 30, 2020 Remaining Project Budget Construction Costs (1) $ 5,524 $ 4,303 $ 1,221 Financing Costs 1,576 1,151 425 Total Costs $ 7,100 $ 5,454 $ 1,646 Project-Level Contingency $ 75 $ — $ 75 Oglethorpe-Level Contingency 325 — 325 Total Contingency $ 400 $ — $ 400 Totals $ 7,500 $ 5,454 $ 2,046 (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement.

General (Details)

General (Details)	6 Months Ended
	Jun. 30, 2020member
Organization, Consolidation and Presentation of Financial Statements [Abstract]
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 ($)	6 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Fair value
Nuclear decommissioning trust fund	$ 509,348,000	$ 511,339,000
Long-term investments	331,000,000	254,864,000
Natural gas swaps
Fair value
Derivative liabilities	31,929,000	32,256,000
International equity trust
Fair value
Unfunded commitments	$ 0
Redemption notice period	3 days
Recurring basis | Natural gas swaps
Fair value
Derivative liabilities	$ 31,929,000	32,256,000
Recurring basis | Domestic equity
Fair value
Nuclear decommissioning trust fund	162,846,000	179,346,000
Recurring basis | International equity trust
Fair value
Nuclear decommissioning trust fund	93,046,000	96,204,000
Long-term investments	23,044,000	23,161,000
Recurring basis | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	88,181,000	63,849,000
Long-term investments	27,249,000	20,395,000
Recurring basis | US Treasury securities
Fair value
Nuclear decommissioning trust fund	41,699,000	45,522,000
Long-term investments	6,408,000	9,257,000
Recurring basis | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	62,873,000	62,400,000
Long-term investments	12,884,000	12,867,000
Recurring basis | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	50,577,000	55,522,000
Long-term investments	124,595,000	126,380,000
Recurring basis | Municipal bonds
Fair value
Nuclear decommissioning trust fund	1,398,000	1,189,000
Recurring basis | Federal agency securities
Fair value
Nuclear decommissioning trust fund	1,348,000	2,586,000
Long-term investments	1,161,000	1,082,000
Recurring basis | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	1,377,000
Recurring basis | Treasury STRIPS
Fair value
Long-term investments	133,392,000	59,816,000
Recurring basis | Other
Fair value
Nuclear decommissioning trust fund	6,003,000	4,721,000
Long-term investments	2,267,000	1,906,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Natural gas swaps
Fair value
Derivative liabilities	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic equity
Fair value
Nuclear decommissioning trust fund	162,846,000	179,346,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | International equity trust
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	41,699,000	45,522,000
Long-term investments	6,408,000	9,257,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	50,577,000	55,522,000
Long-term investments	124,595,000	126,380,000
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Treasury STRIPS
Fair value
Long-term investments	0	0
Recurring basis | Quoted Prices in Active Markets for Identical Assets (Level 1) | Other
Fair value
Nuclear decommissioning trust fund	6,003,000	4,450,000
Long-term investments	2,267,000	1,906,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Natural gas swaps
Fair value
Derivative liabilities	31,929,000	32,256,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Domestic equity
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | International equity trust
Fair value
Nuclear decommissioning trust fund	93,046,000	96,204,000
Long-term investments	23,044,000	23,161,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	88,181,000	63,849,000
Long-term investments	27,249,000	20,395,000
Recurring basis | Significant Other Observable Inputs (Level 2) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	62,873,000	62,400,000
Long-term investments	12,884,000	12,867,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Other Observable Inputs (Level 2) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	1,398,000	1,189,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	1,348,000	2,586,000
Long-term investments	1,161,000	1,082,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	1,377,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Treasury STRIPS
Fair value
Long-term investments	133,392,000	59,816,000
Recurring basis | Significant Other Observable Inputs (Level 2) | Other
Fair value
Nuclear decommissioning trust fund	0	271,000
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Natural gas swaps
Fair value
Derivative liabilities	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Domestic equity
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | International equity trust
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Corporate bonds and debt
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | US Treasury securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Mortgage backed securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Domestic mutual funds
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Municipal bonds
Fair value
Nuclear decommissioning trust fund	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Federal agency securities
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Non-US Gov't bonds & private placements
Fair value
Nuclear decommissioning trust fund	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Treasury STRIPS
Fair value
Long-term investments	0	0
Recurring basis | Significant Unobservable Inputs (Level 3) | Other
Fair value
Nuclear decommissioning trust fund	0	0
Long-term investments	$ 0	$ 0

Fair Value - Estimated fair val

Fair Value - Estimated fair value of long-term debt (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Carrying Value
Fair Value
Long-term debt	$ 10,105,932	$ 9,726,428
Fair Value | Significant Other Observable Inputs (Level 2)
Fair Value
Long-term debt	$ 12,893,268	$ 11,180,658

Derivative Instruments - Gas he

Derivative Instruments - Gas hedges (Details) - Natural gas swaps $ in Thousands, MMBTU in Millions	6 Months Ended
	Jun. 30, 2020USD ($)MMBTU	Dec. 31, 2019USD ($)
Derivative Instruments
Derivative liabilities | $	$ 31,929	$ 32,256
Collateral or letters of credit | $	$ 31,929
Notional volume of natural gas derivatives (in MMBTUs)	98.7
2020
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	17
2021
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	25.6
2022
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	18.3
2023
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	14.4
2024
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	13.2
2025
Derivative Instruments
Notional volume of natural gas derivatives (in MMBTUs)	10.2

Derivative Instruments - Fair v

Derivative Instruments - Fair value of derivative instruments not designated as hedging (Details) - Natural gas swaps - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Liabilities:
Fair value of liabilities	$ 31,929	$ 32,256
Other current assets
Assets:
Fair value of assets	0	0
Other current liabilities
Liabilities:
Fair value of liabilities	15,359	12,898
Other deferred credits
Liabilities:
Fair value of liabilities	$ 16,570	$ 19,358

Derivative Instruments - Realiz

Derivative Instruments - Realized and unrealized gains and (losses) on derivative instruments (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			$ 31,929	$ 32,256
Natural gas swaps | Regulatory asset
Gains and (losses) on derivative instruments
Net unrealized losses on derivative instruments			31,929	32,256
Natural gas swaps | Fuel
Gains and (losses) on derivative instruments
Gains	$ 0	$ 11	0	224
Losses	(7,141)	(1,126)	(11,593)	(1,799)
Total	$ (7,141)	$ (1,115)	$ (11,593)	$ (1,575)

Investment Securities (Details)

Investment Securities (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Investments, Debt and Equity Securities [Abstract]
Gross unrealized losses greater than one year	$ 11,271	$ 22,352
Percent of gross unrealized losses which have been unrealized for greater than one year	68.00%	86.00%
Gross unrealized losses less than one year	$ 45,247	$ 69,567
Cost
Equity	256,741	258,870
Debt	440,600	354,535
Other	8,270	6,356
Total	705,611	619,761
Gains
Equity	125,801	144,832
Debt	21,243	8,474
Other	0	0
Total	147,044	153,306
Losses
Equity	(11,151)	(5,990)
Debt	(1,146)	(874)
Other	(10)	0
Total	(12,307)	(6,864)
Fair Value
Equity	371,391	397,712
Debt	460,697	362,135
Other	8,260	6,356
Total	$ 840,348	$ 766,203

Revenue Recognition (Details)

Revenue Recognition (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020USD ($)	Jun. 30, 2019USD ($)	Jun. 30, 2020USD ($)memberservice	Jun. 30, 2019USD ($)	Dec. 31, 2019USD ($)
Revenue Recognition
Number of electric distribution cooperative members | member			38
Number of services provided | service			2
Member energy requirements supplied	59.00%	59.00%	55.00%	56.00%
Margins for interest ratio			1.10
Targeted margins for interest ratio			1.14
Refund liability	$ 5,850	$ 4,500	$ 5,850	$ 4,500
Operating revenues	330,944	358,860	672,618	715,460
Members
Revenue Recognition
Operating revenues	330,768	358,736	672,281	715,206
Receivables from contracts with members	231,105		231,105		$ 142,946
Capacity revenues | Members
Revenue Recognition
Operating revenues	240,256	235,049	499,649	481,035
Energy revenues | Members
Revenue Recognition
Operating revenues	$ 90,512	$ 123,687	$ 172,632	$ 234,171

Revenue Recognition - Managemen

Revenue Recognition - Management Program (Details) - USD ($)	6 Months Ended		12 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2018
Vogtle Units No. 3 & No. 4
Operating revenues
Amounts billed under rate management program	$ 7,893,000	$ 8,966,000
Cumulative recovery of financing costs	89,152,000
Vogtle New Units
Operating revenues
Cumulative recovery of financing costs	149,426,000
Rate management program, additional collection period			5 years
Rate management program, billing period			5 years
Amounts billed under additional rate management program	$ 60,939,000	$ 23,380,000

Leases - Summary (Details)

Leases - Summary (Details)	6 Months Ended
	Jun. 30, 2020optionlease
Minimum
Leases
Finance lease renewal term	1 year
Maximum
Leases
Finance lease renewal term	5 years
Lease terms through December 31, 2027
Leases
Number of finance leases	3
Lease terms through June 30, 2031
Leases
Number of finance leases	1
Lease terms through February 2042
Leases
Number of renewal options | option	1
Operating lease, renewal term	20 years
Scherer Unit No. 2
Leases
Percentage of undivided interest in Scherer Unit No. 2	60.00%
Number of finance leases	4

Leases - Balance Sheet Impact (

Leases - Balance Sheet Impact (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Right-of-Use Assets—Finance leases
Right-of-use assets	$ 302,732	$ 302,732
Less: Accumulated provision for depreciation	(260,139)	(257,504)
Total finance lease assets	42,593	45,228
Lease liabilities—Finance leases
Obligations under finance leases	72,354	75,649
Long-term debt and finance leases due within one year	6,418	6,081
Total finance lease liabilities	78,772	81,730
Right-of-Use Assets—Operating leases
Electric plant in service	3,795	3,237
Total operating lease assets	3,795	3,237
Lease liabilities—Operating leases
Capitalization—Other	2,889	2,293
Other current liabilities	1,001	1,252
Total operating lease liabilities	$ 3,890	$ 3,545

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Lease Cost
Amortization of leased assets	$ 1,344	$ 1,189	$ 2,688	$ 2,378
Interest on lease liabilities	2,217	2,372	4,434	4,744
Operating lease cost:	272	883	795	1,766
Total leased cost	$ 3,833	$ 4,444	$ 7,917	$ 8,888
Weighted-average remaining lease term (in years)
Finance leases	8 years 7 months 2 days		8 years 7 months 2 days		8 years 10 months 2 days
Operating leases	7 years 4 months 2 days		7 years 4 months 2 days		7 years 4 months 20 days
Weighted-average discount rate:
Finance leases	11.05%		11.05%		11.05%
Operating leases	4.62%		4.62%		5.12%

Leases - Other Lease Disclosure

Leases - Other Lease Disclosures (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Lessee
Operating cash flows from finance leases			$ 4,516	$ 0
Operating cash flows from operating leases			950	1,840
Financing cash flows from finance leases			2,959	0
Right-of-use assets obtained in exchange for new operating lease liabilities			1,227	6,983
Finance Leases
2020	$ 7,475		7,475
2021	14,949		14,949
2022	14,949		14,949
2023	14,949		14,949
2024	14,949		14,949
Thereafter	55,533		55,533
Total lease payments	122,804		122,804
Less: imputed interest	(44,032)		(44,032)
Total finance lease liabilities	78,772		78,772		$ 81,730
Operating Leases
2020	612		612
2021	1,121		1,121
2022	930		930
2023	709		709
2024	235		235
Thereafter	1,085		1,085
Total lease payments	4,692		4,692
Less: imputed interest	(802)		(802)
Total operating lease liabilities	3,890		3,890		$ 3,545
Total
2020	8,087		8,087
2021	16,070		16,070
2022	15,879		15,879
2023	15,658		15,658
2024	15,184		15,184
Thereafter	56,618		56,618
Total lease payments	127,496		127,496
Less: imputed interest	(44,834)		(44,834)
Present value of lease liabilities	82,662		82,662
Lessor
Lease income	$ 1,542	$ 1,522	$ 3,090	$ 3,040

Restricted Investments (Details

Restricted Investments (Details) $ in Thousands	Oct. 01, 2020	Jun. 30, 2020USD ($)	Dec. 31, 2019USD ($)
Restricted Investments
Guaranteed interest rate on deposit (as a percent)		0.05
Restricted investments		$ 546,939	$ 533,590
Restricted investments, long-term		$ 355,340	$ 461,757
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	6 Months Ended
	Jun. 30, 2020	Dec. 31, 2019
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 758,503	$ 763,512
Total Regulatory Liabilities	407,255	364,241
Net Regulatory Assets	351,248	399,271
Accumulated retirement costs for other obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	18,343	12,692
Deferral of effects on net margin | Hawk Road Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Liabilities	18,177	18,485
Major maintenance reserve
Regulatory Assets and Liabilities
Total Regulatory Liabilities	41,768	50,144
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Liabilities	12,806	14,256
Deferred debt service adder
Regulatory Assets and Liabilities
Total Regulatory Liabilities	119,115	114,453
Asset Retirement Obligations
Regulatory Assets and Liabilities
Total Regulatory Liabilities	38,711	61,516
Revenue deferral plan
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 155,117	90,066
Amortization Period	5 years
Other regulatory liabilities
Regulatory Assets and Liabilities
Total Regulatory Liabilities	$ 3,218	2,629
Other regulatory liabilities | Maximum
Regulatory Assets and Liabilities
Amortization Period	7 years
Premium and loss on reacquired debt
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 37,624	40,067
Premium and loss on reacquired debt | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	24 years
Amortization of financing leases
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 35,381	35,433
Outage costs
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 43,093	34,367
Coal-fired maintenance outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	60 months
Nuclear refueling outage costs | Minimum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	18 months
Nuclear refueling outage costs | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	24 months
Asset Retirement Obligations | Ashpond and other
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 236,834	245,932
Depreciation expense
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 39,108	39,820
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	$ 54,113	53,466
Interest rate options cost
Regulatory Assets and Liabilities
Total Regulatory Assets	124,444	121,938
Deferral of effects on net margin - Smith Energy Facility | Smith Energy Facility
Regulatory Assets and Liabilities
Total Regulatory Assets	151,592	154,564
Other regulatory assets
Regulatory Assets and Liabilities
Total Regulatory Assets	$ 36,314	$ 37,925
Other regulatory assets | Maximum
Regulatory Assets and Liabilities
Amortization period, other regulatory assets	30 years

Debt - Department of Energy Loa

Debt - Department of Energy Loan Guarantee (Details)	6 Months Ended
	Jun. 30, 2020USD ($)	Mar. 22, 2019USD ($)	Dec. 31, 2017USD ($)	Feb. 20, 2014USD ($)note
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 | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 3,457,348,000
Long-term debt | FFB
Debt
Number of future advance promissory notes | note				2
Maximum borrowing capacity	4,633,028,088	$ 4,676,749,167		$ 3,057,069,461
Capitalized interest				335,471,604
Maximum borrowing capacity designated for capitalized interest				$ 43,721,079
Eligible project costs, percent		70.00%
Long-term debt | FFB | Department of Energy guarantee
Debt
Aggregate borrowings including capitalized interest	$ 444,000,000	$ 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) - Long-term debt - FFB - Rural Utilities Service Guaranteed Loans - USD ($) $ in Thousands	1 Months Ended	6 Months Ended
	Jul. 31, 2020	Jun. 30, 2020
Debt
Advances received on loans		$ 40,089
Subsequent Event
Debt
Advances received on loans	$ 5,836

Debt - Lines of Credit (Details

Debt - Lines of Credit (Details) - USD ($)	Mar. 31, 2020	Mar. 27, 2020	Mar. 26, 2020
Debt
Payments to acquire pollution control bond	$ 212,760,000
Line of Credit
Debt
Maximum borrowing capacity	1,200,000,000
Line of Credit | JPMorgan Chase
Debt
Maximum borrowing capacity		$ 363,000,000	$ 150,000,000
Borrowings under lines of credit	$ 213,000,000

Vogtle Units No. 3 and No. 4 _3

Vogtle Units No. 3 and No. 4 Construction Project - Narrative (Details) - Vogtle Units No. 3 & No. 4 $ in Millions	1 Months Ended		6 Months Ended	12 Months Ended
	Apr. 30, 2020	Aug. 31, 2018USD ($)	Jun. 30, 2020USD ($)unit	Dec. 31, 2008unitMW
Public Utility Property Plant and Equipment
Ownership interest (as a percent)			30.00%
Total investment in additional Vogtle units			$ 5,500
Construction contingency estimate		$ 800	800
Estimated project-level construction contingency		$ 240
Allocated project level contingency			425
Allocated project level contingency from interest in project level budget			128
Excess project contingency, total			75
Ownership amount of excess project contingency			23
Additional construction contingency, total			250
Ownership amount of additional project level contingency			75
Company level contingency			325
Workforce reduction, percent	20.00%
Minimum
Public Utility Property Plant and Equipment
COVID related costs			150
Ownership amount of COVID related costs			45
Maximum
Public Utility Property Plant and Equipment
COVID related costs			250
Ownership amount of COVID related costs			$ 75
Ownership participation agreement
Public Utility Property Plant and Equipment
Number of additional nuclear units | unit			2
Ownership interest (as a percent)			30.00%
Project budget			$ 7,500
Project extension term			1 year
EPC Agreement | Westinghouse Electric Company LLC and Stone & Webster, Inc.
Public Utility Property Plant and Equipment
Number of nuclear units | unit				2
Generating capacity of each nuclear unit | 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
Global Amendments To Term Sheet
Public Utility Property Plant and Equipment
Percentage of costs disallowed for recovery			6.00%
Global Amendments To Term Sheet | Minimum
Public Utility Property Plant and Equipment
Percentage of ownership approval to change primary construction contractor			90.00%

Vogtle Units No. 3 and No. 4 _4

Vogtle Units No. 3 and No. 4 Construction Project - Project Budget and Actual Costs (Details) - Vogtle Units No. 3 & No. 4 $ in Millions	6 Months Ended
	Jun. 30, 2020USD ($)
Project Budget
Project-Level Contingency	$ 75
Oglethorpe-Level Contingency	325
Remaining Project Budget
Proceeds from guarantee agreement	1,100
Jointly Owned Nuclear Power Plant
Project Budget
Construction Costs	5,524
Financing Costs	1,576
Total Costs	7,100
Project-Level Contingency	75
Oglethorpe-Level Contingency	325
Total Contingency	400
Total Contingency	7,500
Actual Costs
Construction Costs	4,303
Financing Costs	1,151
Total Costs	5,454
Project-Level Contingency	0
Oglethorpe-Level Contingency	0
Total Contingency	0
Totals	5,454
Remaining Project Budget
Construction Costs	1,221
Financing Costs	425
Total Costs	1,646
Project-Level Contingency	75
Oglethorpe-Level Contingency	325
Total Contingency	400
Totals	$ 2,046