UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________________________________________________________________________

FORM 10-Q

(Mark One)

☒    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2020

OR

☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                                    to                                     

Commission File No. 333-192954

(An Electric Membership Corporation)

(Exact name of registrant as specified in its charter)

Georgia (State or other jurisdiction of incorporation or organization)	58-1211925 (I.R.S. employer identification no.)
2100 East Exchange Place Tucker, Georgia (Address of principal executive offices)	30084-5336 (Zip Code)
Registrant's telephone number, including area code	(770) 270-7600

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  ☐    No ☒

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒    No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ☐    Accelerated Filer ☐    Non-Accelerated Filer ☒    Smaller Reporting Company ☐    Emerging Growth Company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐    No ☒

Securities registered pursuant to Section 12(b) of the Act:

Title of each class:	Trading Symbol(s)	Name of each exchange on which registered:
None	N/A	N/A

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date. The registrant is a membership corporation and has no authorized or outstanding equity securities.

OGLETHORPE POWER CORPORATION

INDEX TO QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2020

		Page No.
PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements	1
	Unaudited Consolidated Balance Sheets as of September 30, 2020 and December 31, 2019	1
	Unaudited Consolidated Statements of Revenues and Expenses For the Three and Nine Months ended September 30, 2020 and 2019	3
	Unaudited Consolidated Statements of Patronage Capital and Membership Fees For the Three and Nine Months ended September 30, 2020 and 2019	4
	Unaudited Consolidated Statements of Cash Flows For the Nine Months ended September 30, 2020 and 2019	5
	Notes to Unaudited Consolidated Financial Statements	6
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4.	Controls and Procedures	31
PART II—OTHER INFORMATION
Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.	Defaults Upon Senior Securities	32
Item 4.	Mine Safety Disclosures	32
Item 5.	Other Information	33
Item 6.	Exhibits	34
SIGNATURES		35

i

CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

This quarterly report on Form 10-Q contains "forward-looking statements." All statements, other than statements of historical facts, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as future capital expenditures, business strategy, regulatory actions, and development, construction or operation of facilities (often, but not always, identified through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook") are forward-looking statements.

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 2019 and under "Risk Factors" and in other sections of this quarterly report on Form 10-Q. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this quarterly report may not occur.

Any forward-looking statement speaks only as of the date of this quarterly report, and, except as required by law, we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement. Factors that could cause actual results to differ materially from those indicated in any forward-looking statement include, but are not limited to:

•cost increases and schedule delays with respect to our capital improvement and construction projects, in particular, the construction of two additional nuclear units at Plant Vogtle;

•the duration and severity of the current coronavirus ("COVID-19") pandemic and resulting economic disruption and

its impact on our business, financial condition, operations, construction projects, including the additional units at Plant Vogtle, and our members and their service territories;

•a decision by Georgia Power Company to cancel the additional Vogtle units or a decision by more than 10% of the co-owners of the additional Vogtle units not to proceed with the construction of the additional Vogtle units upon the occurrence of certain material adverse events;

•decisions made by the Georgia Public Service Commission in the regulatory process related to the two additional units at Plant Vogtle;

•our access to capital, the cost to access capital, and the results of our financing and refinancing efforts, including availability of funds in the capital markets;

•our ability to receive advances under the U.S. Department of Energy loan guarantee agreement for constructing two additional nuclear units at Plant Vogtle;

•the occurrence of certain events that give the Department of Energy the option to require that we repay all amounts outstanding under the loan guarantee agreement with the Department of Energy over a five-year period and its decision to require such repayment;

•the continued availability of funding from the Rural Utilities Service;

•the impact of regulatory or legislative responses to climate change initiatives or efforts to reduce greenhouse gas emissions, including carbon dioxide;

•costs associated with achieving and maintaining compliance with applicable environmental laws and regulations, including those related to air emissions, water and coal combustion byproducts;

•legislative and regulatory compliance standards and our ability to comply with any applicable standards, including mandatory reliability standards, and potential penalties for non-compliance;

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•increasing debt caused by significant capital expenditures;

•unanticipated changes in capital expenditures, operating expenses and liquidity needs;

•actions by credit rating agencies;

•commercial banking and financial market conditions;

•risks and regulatory requirements related to the ownership and construction of nuclear facilities;

•adequate funding of our nuclear decommissioning trust funds including investment performance and projected decommissioning costs;

•continued efficient operation of our generation facilities by us and third-parties;

•the availability of an adequate and economical supply of fuel, water and other materials;

•reliance on third-parties to efficiently manage, distribute and deliver generated electricity;

•acts of sabotage, wars or terrorist activities, including cyber attacks;

•changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories, including from the development and deployment of distributed generation and energy storage technologies;

•early retirement of one or more of our co-owned coal facilities;

•the inability of counterparties to meet their obligations to us, including failure to perform under agreements;

•our members' ability to perform their obligations to us;

•our members' ability to offer their residential, commercial and industrial customers competitive rates;

•changes to protections granted by the Georgia Territorial Act that subject our members to increased competition;

•unanticipated variation in demand for electricity or load forecasts resulting from changes in population and business growth (and declines), consumer consumption, energy conservation and efficiency efforts and the general economy;

•general economic conditions;

•weather conditions and other natural phenomena;

•litigation or legal and administrative proceedings and settlements;

•unanticipated changes in interest rates or rates of inflation;

•significant changes in our relationship with our employees, including the availability of qualified personnel;

•significant changes in critical accounting policies material to us;

•hazards customary to the electric industry and the possibility that we may not have adequate insurance to cover losses resulting from these hazards;

•catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events, such as influenza, or similar occurrences; and

•other factors discussed elsewhere in this quarterly report or in other reports we file with the SEC.

iii

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Oglethorpe Power Corporation

Consolidated Balance Sheets (Unaudited)

 September 30, 2020 and December 31, 2019

	(dollars in thousands)
	2020		2019
Assets
Electric plant:
In service	$	9,375,405	$	9,209,983
Right-of-use assets—finance leases	302,732		302,732
Less: Accumulated provision for depreciation	(4,939,712)		(4,833,025)
	4,738,425		4,679,690
Nuclear fuel, at amortized cost	354,942		359,270
Construction work in progress	5,535,768		4,816,896
Total electric plant	10,629,135		9,855,856
Investments and funds:
Nuclear decommissioning trust fund	540,726		511,339
Investment in associated companies	74,424		73,318
Long-term investments	416,418		254,864
Restricted investments	301,163		461,757
Other	27,593		26,422
Total investments and funds	1,360,324		1,327,700
Current assets:
Cash and cash equivalents	383,868		448,612
Restricted short-term investments	239,709		71,833
Receivables	169,808		166,429
Inventories, at average cost	274,004		277,729
Prepayments and other current assets	43,372		9,862
Total current assets	1,110,761		974,465
Deferred charges:
Regulatory assets	739,089		763,512
Prepayments to Georgia Power	35,607		48,052
Other	22,136		20,528
Total deferred charges	796,832		832,092
Total assets	$	13,897,052	$	12,990,113

The accompanying notes are an integral part of these consolidated financial statements.

1

Oglethorpe Power Corporation

Consolidated Balance Sheets (Unaudited)

 September 30, 2020 and December 31, 2019

	(dollars in thousands)
	2020		2019
Equity and Liabilities
Capitalization:
Patronage capital and membership fees	$	1,074,584	$	1,016,747
Long-term debt	10,151,505		9,403,847
Obligation under finance leases	72,354		75,649
Other	26,627		25,196
Total capitalization	11,325,070		10,521,439
Current liabilities:
Long-term debt and finance leases due within one year	235,118		217,440
Short-term borrowings	266,115		282,370
Accounts payable	143,621		165,049
Accrued interest	76,378		65,895
Member power bill prepayments, current	56,416		77,066
Other current liabilities	58,404		49,443
Total current liabilities	836,052		857,263
Deferred credits and other liabilities:
Asset retirement obligations	1,127,670		1,070,640
Member power bill prepayments, non-current	98,071		134,396
Regulatory liabilities	480,446		364,241
Other	29,743		42,134
Total deferred credits and other liabilities	1,735,930		1,611,411
Total equity and liabilities	$	13,897,052	$	12,990,113

The accompanying notes are an integral part of these consolidated financial statements.

2

Oglethorpe Power Corporation

Consolidated Statements of Revenues and Expenses (Unaudited)

 For the Three and Nine Months Ended September 30, 2020 and 2019

	(dollars in thousands)
	Three Months				Nine Months
	2020		2019		2020		2019
Operating revenues:
Sales to Members	$	365,937	$	382,548	$	1,038,218	$	1,097,754
Sales to non-Members	302		75		639		329
Total operating revenues	366,239		382,623		1,038,857		1,098,083
Operating expenses:
Fuel	131,925		138,704		282,677		349,146
Production	94,071		93,092		303,705		301,996
Depreciation and amortization	61,758		60,574		186,370		183,212
Purchased power	16,419		17,716		49,366		50,415
Accretion	14,204		13,328		40,830		36,361
Total operating expenses	318,377		323,414		862,948		921,130
Operating margin	47,862		59,209		175,909		176,953
Other income:
Investment income	11,672		14,144		36,210		45,129
Other	1,832		623		5,733		1,565
Total other income	13,504		14,767		41,943		46,694
Interest charges:
Interest expense	101,600		100,687		305,128		301,864
Allowance for debt funds used during construction	(51,518)		(47,909)		(153,595)		(138,246)
Amortization of debt discount and expense	2,813		2,912		8,482		8,764
Net interest charges	52,895		55,690		160,015		172,382
Net margin	$	8,471	$	18,286	$	57,837	$	51,265

The accompanying notes are an integral part of these consolidated financial statements.

3

Oglethorpe Power Corporation

Consolidated Statements of Patronage Capital and Membership Fees (Unaudited)

 For the Three and Nine Months Ended September 30, 2020 and 2019

	(dollars in thousands)
Balance at December 31, 2018	$	962,286
Net margin	23,596
Balance at March 31, 2019	$	985,882
Net margin	9,383
Balance at June 30, 2019	$	995,265
Net margin	18,286
Balance at September 30, 2019	$	1,013,551
Balance at December 31, 2019	$	1,016,747
Net margin	23,204
Balance at March 31, 2020	$	1,039,951
Net margin	26,162
Balance at June 30, 2020	$	1,066,113
Net margin	8,471
Balance at September 30, 2020	$	1,074,584

The accompanying notes are an integral part of these consolidated financial statements.

4

Oglethorpe Power Corporation

Consolidated Statements of Cash Flows (Unaudited)

 For the Nine Months Ended September 30, 2020 and 2019

	(dollars in thousands)
	2020		2019
Cash flows from operating activities:
Net margin	$	57,837	$	51,265
Adjustments to reconcile net margin to net cash provided by operating activities:
Depreciation and amortization, including nuclear fuel	278,872		281,049
Accretion cost	40,830		36,361
Amortization of deferred gains	(1,341)		(1,341)
Allowance for equity funds used during construction	(306)		(569)
Deferred outage costs	(36,502)		(26,925)
Gain on sale of investments	(14,122)		(4,611)
Regulatory deferral of costs associated with nuclear decommissioning	(11,482)		(17,686)
Other	(2,566)		(549)
Change in operating assets and liabilities:
Receivables	(22,751)		(1,706)
Inventories	3,836		(13,238)
Prepayments and other current assets	(30,914)		(2,256)
Accounts payable	(28,764)		(60,068)
Accrued interest	10,483		6,147
Accrued taxes	35,004		34,435
Other current liabilities	(16,433)		(26,761)
Member power bill prepayments	(56,975)		(94,398)
Rate management program collections	114,006		37,982
Total adjustments	260,875		145,866
Net cash provided by operating activities	318,712		197,131
Cash flows from investing activities:
Property additions	(983,902)		(887,160)
Activity in nuclear decommissioning trust fund—Purchases	(393,369)		(281,821)
—Proceeds	387,277		275,545
Increase (decrease) in restricted investments	(7,282)		89,175
Activity in other long-term investments—Purchases	(285,842)		(165,743)
—Proceeds	136,476		134,907
Other	9,075		(9,674)
Net cash used in investing activities	(1,137,567)		(844,771)
Cash flows from financing activities:
Long-term debt proceeds	2,045,685		683,008
Long-term debt payments	(1,274,196)		(477,360)
(Decrease) increase in short-term borrowings, net	(16,255)		124,044
Other	(1,123)		(7,631)
Net cash provided by financing activities	754,111		322,061
Net decrease in cash and cash equivalents	(64,744)		(325,579)
Cash and cash equivalents at beginning of period	448,612		752,618
Cash and cash equivalents at end of period	$	383,868	$	427,039
Supplemental cash flow information:
Cash paid for—
Interest (net of amounts capitalized)	$	139,878	$	156,370
Supplemental disclosure of non-cash investing and financing activities:
Change in asset retirement obligations	$	22,086	$	5,053
Accrued property additions at end of period	$	94,365	$	103,390
Interest paid-in-kind	$	—	$	55,767

The accompanying notes are an integral part of these consolidated financial statements.

5

Oglethorpe Power Corporation

Notes to Unaudited Consolidated Financial Statements

(A)General.    The consolidated financial statements included in this report have been prepared by us pursuant to the rules and regulations of the Securities and Exchange Commission. In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the three-month and nine-month periods ended September 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.

These unaudited consolidated financial statements should be read in conjunction with the audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2019, as filed with the SEC. The results of operations for the three- and nine-month periods ended September 30, 2020 are not necessarily indicative of results to be expected for the full year. As noted in our 2019 Form 10-K, our revenues consist primarily of sales to our 38 electric distribution cooperative members and, thus, the receivables on the consolidated balance sheets are principally from our members. See "Notes to Consolidated Financial Statements" in our 2019 Form 10-K.

(B)Fair Value.    Authoritative guidance regarding fair value measurements for financial and non-financial assets and liabilities defines fair value, establishes a framework for measuring fair value in accordance with generally accepted accounting principles, and expands disclosures about fair value measurements.

The guidance establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

•Level 1.  Quoted prices from active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Quoted prices in active markets provide the most reliable evidence of fair value and are used to measure fair value whenever available. Level 1 primarily consists of financial instruments that are exchange-traded.

•Level 2.  Pricing inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Level 2 primarily consists of financial instruments that are non-exchange-traded but have significant observable inputs.

•Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs.

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.

6

3.Cost approach.    The cost approach is based on the amount that currently would be required to replace the service capacity of an asset (often referred to as current replacement cost). This approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset or comparable utility, adjusted for obsolescence.

The tables below detail assets and liabilities measured at fair value on a recurring basis at September 30, 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
	September 30, 2020		(Level 1)		(Level 2)		(Level 3)
	(dollars in thousands)
Nuclear decommissioning trust funds:
Domestic equity	$	177,002	$	177,002	$	—	$	—
International equity trust	102,877		—		102,877		—
Corporate bonds and debt	95,579		—		95,237		342
US Treasury securities	40,416		40,416		—		—
Mortgage backed securities	49,749		—		49,749		—
Domestic mutual funds	55,568		55,568		—		—
Municipal bonds	1,407		—		1,407		—
Federal agency securities	8,699		—		8,699		—
Non-US Gov't bonds & private placements	2,055		—		2,055		—
Other	7,374		7,374		—		—
Long-term investments:
International equity trust	26,751		—		26,751		—
Corporate bonds and debt	30,260		—		30,050		210
US Treasury securities	4,034		4,034		—		—
Mortgage backed securities	12,757		—		12,757		—
Domestic mutual funds	162,346		162,346		—		—
Federal agency securities	625		—		625		—
Treasury STRIPS	176,672		—		176,672		—
Other	2,973		2,973		—		—
Natural gas swaps	4,808		—		4,808		—

7

	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 September 30, 2020 and December 31, 2019 were as follows:

	2020				2019
	Carrying Value		Fair Value		Carrying Value		Fair Value
	​(in thousands)
Long-term debt	$	10,500,876	$	13,228,028	$	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 September 30, 2020 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank.

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For cash and cash equivalents, and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account and the carrying amount of these investments approximates fair value because of the liquid nature of the deposits with the U.S. Treasury.

(C)Derivative Instruments.    We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting to derivative transactions, but instead apply regulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate. Realized gains and losses on natural gas swaps are included in fuel expense within our consolidated statements of revenues and expenses and, therefore, net margins within our consolidated statement of cash flows.

We are exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. We have established policies and procedures to manage credit risk through counterparty analysis, exposure calculation and monitoring, exposure limits, collateralization and certain other contractual provisions.

It is possible that volatility in commodity prices could cause us to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of September 30, 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 September 30, 2020 and December 31, 2019, the estimated fair values of our natural gas contracts were net liabilities of approximately $4,808,000 and $32,256,000, respectively.

As of September 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 September 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 $4,811,000 with our counterparties.

The following table reflects the notional volume of our natural gas derivatives as of September 30, 2020 that is expected to settle or mature each year:

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Year	Natural Gas Swaps (MMBTUs)  (in millions)
2020	4.5
2021	26.4
2022	19.6
2023	16.5
2024	15.7
2025	10.2
Total	92.9

The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at September 30, 2020 and December 31, 2019.

	Balance Sheet Location	Fair Value
		2020		2019
		(dollars in thousands)
Assets:
Natural gas swaps	Other current assets	$	2,596	$	—
Liabilities:
Natural gas swaps	Other current liabilities	$	106	$	12,898
Natural gas swaps	Other deferred credits	$	7,298	$	19,358

The following table presents the gross realized gains and (losses) on derivative instruments recognized in net margins for the three and nine months ended September 30, 2020 and 2019.

	Statement of Revenues and Expenses Location	Three Months Ended September 30,				Nine Months Ended September 30,
		2020		2019		2020		2019
		(dollars in thousands)
Natural Gas Swaps gains	Fuel	$	339	$	—	$	339	$	224
Natural Gas Swaps losses	Fuel	(8,721)		(6,294)		(20,314)		(8,093)
Total		$	(8,382)	$	(6,294)	$	(19,975)	$	(7,869)

The following table presents the unrealized losses on derivative instruments deferred on the balance sheet at September 30, 2020 and December 31, 2019.

	Balance Sheet Location	2020		2019
		(dollars in thousands)
Natural gas swaps	Regulatory asset	$	4,808	$	32,256
Total		$	4,808	$	32,256

(D)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.

The following tables summarize debt and equity securities as of September 30, 2020 and December 31, 2019.

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	Gross Unrealized
	(dollars in thousands)
September 30, 2020	Cost		Gains		Losses		Fair Value
Equity	$	259,356	$	160,336	$	(11,785)	$	407,907
Debt	519,421		20,198		(940)		538,679
Other	10,564		—		(6)		10,558
Total	$	789,341	$	180,534	$	(12,731)	$	957,144

	Gross Unrealized
	(dollars in thousands)
December 31, 2019	Cost		Gains		Losses		Fair Value
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

(E)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 processes 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.

(F)Revenue Recognition.    As an electric membership cooperative, our principle business is providing wholesale electric service to our members. Our operating revenues are derived primarily from wholesale power contracts we have with each of our 38 members. These contracts, which extend to December 31, 2050, are substantially identical and obligate our members jointly and severally to pay all expenses associated with owning and operating our power supply business. As a cooperative, we operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. While not significant, we also have short-term energy sales to non-members made through industry standard contracts. We do not have multiple operating segments.

Pursuant to our contracts, we primarily provide two services, capacity and energy. Capacity and energy revenues are recognized by us upon transfer of control of promised services to our members and non-members in an amount that

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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 nine-month periods ended September 30, 2020 and 2019, we provided approximately 57% 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 September 30, 2020 and September 30, 2019, we recognized refund liabilities totaling $21,400,000 and $7,700,000, respectively. Based on our current agreements with non-members, we do not refund any consideration received from non-members.

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Sales to members for the three and nine months ended September 30, 2020 and 2019 were as follows:

	Three Months Ended September 30,						Nine Months Ended September 30,
	(dollars in thousands)
	2020			2019			2020			2019
Capacity revenues	$	222,187		$	231,270		$	721,836		$	712,305
Energy revenues	143,750			151,278			316,382			385,449
Total	$	365,937		$	382,548		$	1,038,218		$	1,097,754
Member energy requirements supplied	60		%	57		%	57		%	56		%

Receivables from contracts with our members at September 30, 2020 and December 31, 2019 were $139,390,000 and $142,946,000, respectively.

Sales to non-members during the three and nine months ended September 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 nine months ended September 30, 2020 and September 30, 2019 were $11,805,000 and $12,368,000, respectively. The cumulative amount billed since inception of the program totaled $93,064,000.

In 2018, we began an additional rate management program that allows us to recover future expense on a current basis from our members. In general, the program allows for additional collections over a five-year period with those amounts then applied to billings over the subsequent five-year period. The program is designed primarily as a mechanism to assist our members in managing the rate impacts associated with the commercial operation of the new Vogtle units. Under this program, amounts billed to participating members during the nine months ended September 30, 2020 and September 30, 2019 were $93,390,000 and $35,069,000, respectively. Funds collected through this program are invested and held until applied to members' bills. In conjunction with this program, we are applying regulated operations accounting to defer these revenues and related investment income on the funds collected. Amounts deferred under the program will be amortized to income when applied to members' bills. The cumulative amount billed since inception of the program totaled $181,877,000.

(G)Leases.    As a lessee, we have a relatively small portfolio of leases with the most significant being our 60% undivided interest in Scherer Unit No. 2 and railcar leases for the transportation of coal. We also have various other leases of minimal value.

We classify our four Scherer Unit No. 2 leases as finance leases and our railcar leases as operating leases. We have made an accounting policy election not to recognize right-of-use assets and lease liabilities that arise from short-term leases, leases having an initial term of 12 months or less, for any class of underlying asset. We recognize lease expense for short-term leases on a straight-line basis over the lease term. Lease expense recognized for our short-term leases during the nine months ended September 30, 2020 and September 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.

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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	September 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	(261,457)		(257,504)
Total finance lease assets	$	41,275	$	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	September 30, 2020		December 31, 2019
	(dollars in thousands)
Right-of-Use Assets—Operating leases
Electric plant in service	$	3,550	$	3,237
Total operating lease assets	$	3,550	$	3,237
Lease liabilities—Operating leases
Capitalization—Other	$	2,553	$	2,293
Other current liabilities	1,010		1,252
Total operating lease liabilities	$	3,563	$	3,545

		Three months ended				Nine months ended
Lease Cost	Classification	September 30, 2020		September 30, 2019		September 30, 2020		September 30, 2019
		(dollars in thousands)
Finance lease cost:
Amortization of leased assets	Depreciation and amortization	$	1,344	$	1,189	$	4,032	$	3,567
Interest on lease liabilities	Interest expense	2,217		2,372		6,651		7,116
Operating lease cost:	Inventory(1) & production expense	286		542		1,081		2,308
Total leased cost		$	3,847	$	4,103	$	11,764	$	12,991

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(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.

	September 30, 2020		December 31, 2019
Lease Term and Discount Rate:
Weighted-average remaining lease term (in years)
Finance leases	8.10		8.84
Operating leases	7.39		7.39
Weighted-average discount rate:
Finance leases	11.05	%	11.05	%
Operating leases	4.66	%	5.12	%

	Nine months ended
	September 30, 2020		September 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	$	4,817
Operating cash flows from operating leases	$	1,301	$	2,602
Financing cash flows from finance leases	$	2,959	$	2,658
Right-of-use assets obtained in exchange for new operating lease liabilities	$	—	$	6,983

Maturity analysis of our finance and operating lease liabilities as of September 30, 2020 is as follows:

	(dollars in thousands)
Year Ending December 31,	Finance Leases		Operating Leases		Total
2020	$	7,475	$	261	$	7,736
2021	14,949		1,119		16,068
2022	14,949		929		15,878
2023	14,949		708		15,657
2024	14,949		234		15,183
Thereafter	55,532		1,085		56,617
Total lease payments	$	122,803	$	4,336	$	127,139
Less: imputed interest	(44,031)		(773)		(44,804)
Present value of lease liabilities	$	78,772	$	3,563	$	82,335

As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases.

Lease income recognized during the three and nine months ended September 30, 2020 and September 30, 2019 was as follows:

	Three Months Ended September 30,				Nine months ended September 30,
	2020		2019		2020		2019
	(dollars in thousands)
Lease income	$	1,543	$	1,514	$	4,633	$	4,554

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(H)Contingencies and Regulatory Matters.    We do not anticipate that the liabilities, if any, for any current proceedings against us will have a material effect on our financial condition or results of operations. However, at this time, the ultimate outcome of any pending or potential litigation cannot be determined.

Environmental Matters.    As is typical for electric utilities, we are subject to various federal, state and local environmental laws which represent significant future risks and uncertainties. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. Handling and disposal requirements govern the manner of transportation, storage and disposal of various types of waste. We may also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide.

Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. We believe that we are in compliance with those environmental regulations currently applicable to our business and operations. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance.

At this time, the ultimate impact of any potential new and more stringent environmental regulations described above is uncertain and could have an effect on our financial condition, results of operations and cash flows as a result of future additional capital expenditures and increased operations and maintenance costs.

Additionally, litigation over environmental issues and claims of various types, including property damage, personal injury, common law nuisance, and citizen enforcement of environmental requirements such as air quality and water standards, has increased generally throughout the United States. In particular, personal injury and other claims for damages caused by alleged exposure to hazardous materials, and common law nuisance claims for injunctive relief, personal injury and property damage allegedly caused by coal combustion residue, greenhouse gas and other emissions have become more frequent.

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. For additional information regarding our interest in Plant Scherer, see "Item 2 – PROPERTIES" in our 2019 Form 10-K.

(I)Restricted Investments.    Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit as of September 30, 2020 earned interest at a rate of 5% per annum. Beginning October 1, 2020, deposits earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At September 30, 2020 and December 31, 2019, we had restricted investments totaling $540,871,000 and $533,590,000, respectively, of which $301,163,000 and $461,757,000, respectively, were classified as long-term.

(J)Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members. The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.

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The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of September 30, 2020 and December 31, 2019.

	2020		2019
​	(dollars in thousands)
Regulatory Assets:
Premium and loss on reacquired debt(a)	$	36,529	$	40,067
Amortization of financing leases(b)	35,354		35,433
Outage costs(c)	42,440		34,367
Asset retirement obligations—Ashpond and other(k)	247,125		245,932
Depreciation expense(d)	38,752		39,820
Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e)	54,599		53,466
Interest rate options cost(f)	125,629		121,938
Deferral of effects on net margin—Smith Energy Facility(g)	150,106		154,564
Other regulatory assets(m)	8,555		37,925
Total Regulatory Assets	$	739,089	$	763,512
Regulatory Liabilities:
Accumulated retirement costs for other obligations(h)	$	18,993	$	12,692
Deferral of effects on net margin—Hawk Road Energy Facility(g)	18,023		18,485
Major maintenance reserve(i)	53,057		50,144
Amortization of financing leases(b)	12,081		14,256
Deferred debt service adder(j)	121,443		114,453
Asset retirement obligations—Nuclear(k)	66,458		61,516
Revenue deferral plan(l)	187,600		90,066
Other regulatory liabilities(m)	2,791		2,629
Total Regulatory Liabilities	$	480,446	$	364,241
Net Regulatory Assets	$	258,643	$	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 is placed 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-year period which began in 2018. These amounts will be amortized to income and applied to member billings over the subsequent five-year period.

(m)The amortization periods for other regulatory assets range up to 30 years and the amortization periods of other regulatory liabilities range up to 7 years.

(K)Member Power Bill Prepayments.    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against

17

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 2021.

(L)Debt.

a)Department of Energy Loan Guarantee:

Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we and the U.S. Department of Energy, acting by and through the Secretary of Energy, entered into a Loan Guarantee Agreement on February 20, 2014 pursuant to which the Department of Energy agreed to guarantee our obligations under a Note Purchase Agreement, dated as of February 20, 2014 (the Original Note Purchase Agreement), among us, the Federal Financing Bank and the Department of Energy and two future advance promissory notes, each dated February 20, 2014, made by us to the Federal Financing Bank in the aggregate amount of $3,057,069,461 (the Original FFB Notes and together with the Original Note Purchase Agreement, the Original FFB Documents).

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 could not exceed $3,057,069,461, of which $335,471,604 was designated for capitalized interest. We have advanced all amounts available under the Original FFB Notes. We were unable to advance $43,721,079 of the amount designated for capitalized interest under the Original FFB Notes due to timing of borrowing and lower than expected interest rates.

Borrowings under the Additional FFB Note may not exceed (i) $1,619,679,706 or (ii) an amount that, when aggregated with borrowings under the Original FFB Notes, equals 70% of Eligible Project Costs less the $1,104,000,000 guarantee payment we received from Toshiba Corporation in late 2017. At September 30, 2020, borrowings under the Additional FFB Note totaled $444,000,000.

At September 30, 2020, aggregate Department of Energy-guaranteed borrowings, including capitalized interest, totaled $3,457,348,000.

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. As of September 30, 2020, we have repaid $59,100,000 of principal on the FFB Notes. 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

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construction and we have provided the Department of Energy with certain additional information, (v) certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, (vi) evidence of compliance with the applicable wage requirements of the Davis-Bacon Act, as amended, (vii) certification from the Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs and (viii) if either the Services Agreement or the Bechtel Agreement (each, as described in Note M) are terminated, or rejected in bankruptcy proceedings, the Department of Energy has approved the replacement agreement.

We may voluntarily prepay outstanding borrowings under the Facility. Under the FFB Documents, any prepayment will be subject to a make-whole premium or discount, as applicable. Any amounts prepaid may not be re-borrowed.

Under the Loan Guarantee Agreement, we are subject to customary borrower affirmative and negative covenants and events of default. In addition, we are subject to project-related reporting requirements and other project-specific covenants and events of default.

If certain events occur, referred to as an "Alternate Amortization Event," at the Department of Energy's option the Federal Financing Bank's commitment to make further advances under the Facility will terminate and we will be required to repay the outstanding principal amount of all borrowings under the Facility over a period of five years, with level principal amortization. These events include (i) abandonment of the Vogtle Units No. 3 and No. 4 project, including a decision by Georgia Power to cancel the project, (ii) cessation of the construction of Vogtle Units No. 3 and No. 4 for twelve consecutive months, (iii) termination of the Services Agreement or rejection of the Services Agreement in bankruptcy, if Georgia Power does not maintain access to certain related intellectual property rights, (iv) termination of the Services Agreement by Westinghouse or termination of the Bechtel Agreement by Bechtel Power Corporation, (v) delivery of certain notices by the Co-owners to the Department of Energy of their intent to cancel construction of Vogtle Units No. 3 and No. 4 coupled with termination by the Co-owners of the Services Agreement or the Bechtel Agreement, (vi) failure of the Co-owners to enter into a replacement contract with respect to the Services Agreement or the Bechtel Agreement following the Co-owners' termination of such agreement with the intent to replace it, (vii) the Department of Energy's takeover of construction of Vogtle Units No. 3 and No. 4 under certain conditions, (viii) the occurrence of any Project Adverse Event that results in a cancellation of the Vogtle Units No. 3 and No. 4 project or the cessation or deferral of construction beyond the periods permitted under the Loan Guarantee Amendment, (ix) loss of or failure to receive necessary regulatory approvals under certain circumstances, (x) loss of access to intellectual property rights necessary to construct or operate Vogtle Units No. 3 and No. 4 under certain circumstances, (xi) our failure to fund our share of operation and maintenance expenses for Vogtle Units No. 3 and No. 4 for twelve consecutive months, (xii) change of control of Oglethorpe and (xiii) certain events of loss or condemnation. If we receive proceeds from an event of condemnation relating to Vogtle Units No. 3 and No. 4, such proceeds must be applied to immediately prepay outstanding borrowings under the Facility.

b)Rural Utilities Service Guaranteed Loans:

For the nine-month period ended September 30, 2020, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $45,925,000 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. During the second quarter of 2020, we 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. On July 30, 2020, we repaid these borrowings utilizing proceeds from commercial paper issuances.

d)Pollution Control Revenue Bonds:

On August 25, 2020, we remarketed $212,760,000 of Series 2013A term rate pollution control revenue bonds that were subject to mandatory tender on April 1, 2020. The proceeds from the remarketing were used to repay outstanding commercial paper that was used to refinance the purchase the Series 2013 bonds. The notes issued in connection with the Series 2013 bonds are secured under our first mortgage indenture.

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e)First Mortgage Bonds:

On August 25, 2020, we issued $450,000,000 of 3.75% first mortgage bonds, Series 2020A for the purpose of providing long-term financing for expenditures related to the construction of Vogtle Units No. 3 and No. 4. In conjunction with the issuance, we repaid $439,200,000 of outstanding commercial paper. The bonds are due to mature August 2050 and are secured under our first mortgage indenture.

(M)Vogtle Units No. 3 and No. 4 Construction Project.   We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

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 the Georgia Public Service Commission approved in-service dates of November 2021 and November 2022, respectively. As of September 30, 2020, our total investment in the additional Vogtle units was approximately $5.7 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics.

The August 2018 project-level budget included an $800 million construction contingency estimate, of which our 30% interest was $240 million. As of June 30, 2020, assignments of contingency exceeded the 2018 construction contingency estimate by $75 million of which our 30% interest was $23 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate the impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and

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procurement, among other factors. As a result of these factors, Georgia Power established additional construction contingency of $250 million (of which our 30% interest is $75 million), as of June 30, 2020 for further potential risks, including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. During the third quarter of 2020, approximately $10 million, of which our 30% interest is $3 million, of the construction contingency established in the second quarter of 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support. 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 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 September 30, 2020 for our 30% interest in the project.

	(in millions)
	Project Budget		Actual Costs at September 30, 2020		Remaining Project Budget
Construction Costs (1)	$	5,501	$	4,536	$	965
Financing Costs	1,557		1,204		353
Total Costs	$	7,058	$	5,740	$	1,318
Project-Level Contingency	$	72	$	—	$	72
Oglethorpe-Level Contingency	370		—		370
Total Contingency	$	442	$	—	$	442
Totals	$	7,500	$	5,740	$	1,760
(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. Following peaks in April and July and subsequent declines, the number of active cases of COVID-19 at the site continues to fluctuate and impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not 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. Georgia Power has stated that it expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022, 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

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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 June 15, 2020, the Nuclear Regulatory Commission rejected Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain inspections, tests, analyses, and acceptance criteria. On August 10, 2020, the Atomic Safety Licensing Board rejected the Blue Ridge Environmental Defense League’s May 11, 2020 petition challenging a license amendment request. The staff of the Nuclear Regulatory Commission has issued the requested amendment to the combined construction and operating license for Vogtle Unit No. 3. The Blue Ridge Environmental Defense League appealed the Atomic Safety Licensing Board’s decision to the Nuclear Regulatory Commission. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

The Co-owners' joint ownership agreements, as amended, provide that the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction, or can vote to suspend construction, if certain adverse events occur, including: (i) the bankruptcy of Toshiba Corporation; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement, the Bechtel Agreement or the agency agreement with Southern Nuclear; (iii) Georgia Power publicly announces its intention not to submit for rate recovery any portion of its investment in Vogtle Units No. 3 and No. 4 (or associated financing costs) or the Georgia Public Service Commission determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates, excluding any additional amounts paid by Georgia Power on behalf of the other Co-owners pursuant to the Joint Ownership Agreement and the first 6% of costs during any six-month VCM reporting period that are disallowed by the Public Service Commission for recovery, or for which Georgia Power elects not to seek cost recovery, through retail rates or (iv) an incremental extension of one year or more over the most recently approved schedule (each, a Project Adverse Event).

(N)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

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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.

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Item 2.    Management's Discussion and Analysis of Financial Condition and Results of Operations

General

We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our members are consumer-owned distribution cooperatives providing retail electric service in Georgia on a not-for-profit basis. Our principal business is providing wholesale electric power to our members, which we provide primarily from our generation assets and, to a lesser extent, from power purchased from other suppliers. As with cooperatives generally, we operate on a not-for-profit basis.

Response to COVID-19

In March 2020, the World Health Organization declared a pandemic following the outbreak of COVID-19, a respiratory disease caused by a new strain of coronavirus currently affecting many parts of the world, including the United States and Georgia. In response, most jurisdictions, including the United States and Georgia, instituted restrictions on travel, public gatherings and non-essential business operations. While some of these restrictions have been relaxed in Georgia, many of the restrictions remain in place and there is no guarantee restrictions will not be reimposed. As a result of the COVID-19 pandemic and the subsequent protective measures to mitigate the spread of the virus, there have been significant economic disruptions globally and in the United States, including Georgia and our members' service territories.

As an electric utility, we are deemed part of the nation's critical infrastructure and have continued operating during the pandemic to provide electricity to our members and the populations they serve. To protect our associates and the public and to maintain operating capabilities, we implemented applicable business continuity plans, including working remotely where possible; increased cleaning frequency at business locations; implemented applicable safety and health guidelines issued by federal and state officials; and established protocols to maintain generation reliability. In June, we began a phased reopening of our corporate offices with new safety protocols intended to reduce the risk of transmission of COVID-19. To date, these measures have been effective in maintaining our critical operations and we continue to keep in contact with state and federal regulators to ensure the safety of our associates and reliability of our generation facilities.

The recent and ongoing economic disruptions are unprecedented and have reduced energy demand, primarily in the commercial and industrial classes. As a partial offset to these reductions, social distancing and remote work policies have increased demand from residential customers in the short term. Approximately two-thirds of our members' sales are to residential customers. For the third quarter of 2020, our preliminary analysis indicates that the impact of COVID-19 on our members’ sales was relatively minor. Since the pandemic began, we estimate that the overall impact of COVID-19 on our members’ sales is a reduction of approximately one to two percent. The ultimate impact on us and our members, including demand for electricity and the continued ability of our members' customers' to pay for electric service, is subject to many factors, including the duration and severity of the COVID-19 pandemic and the resulting economic conditions.

In addition, the COVID-19 pandemic has impacted productivity levels and the pace of activity completion at Vogtle Units No. 3 and No. 4 and temporarily disrupted capital markets that had a short-term impact on the fair value of certain of our investments and our ability to issue commercial paper for certain periods of 2020. While the ultimate outcome of these matters is uncertain, to date, the COVID-19 pandemic has not had a material impact on our business, financial condition or operations.

Additional information regarding COVID-19 and its potential impacts on us and our members is in "Risk Factors."

Results of Operations

For the Three and Nine Months Ended September 30, 2020 and 2019

Net Margin

Our net margins for the three-month and nine-month periods ended September 30, 2020 were $8.5 million and $57.8 million, respectively, compared to $18.3 million and $51.3 million for the same periods of 2019. For the nine-months ended September 30, 2020, our net margin was approximately 103% of our targeted net margin of $55.9 million for the year ending December 31, 2020. In June 2020, our board of directors approved a budget revision which will reduce revenues $6.5 million by year-end. We anticipate our board of directors will approve another budget adjustment by year end so that margins will achieve, but not exceed, the 2020 targeted margins for interest ratio of 1.14. As a result, and pursuant to Revenue from Contracts with Customers (Topic 606), we assessed our projected margin and annual revenue requirement to meet the targeted margins for interest ratio and recognized cumulative refund liabilities of $21.4 million and $7.7 million as of September 30, 2020 and 2019, respectively. For additional information regarding our net margin requirements and policy, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Margins" in our 2019 Form 10-K.

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Operating Revenues

Our operating revenues fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in our members' service territories, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned, purchased or member-owned resources over which we have dispatch rights, and our members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

For the quarter ended September 30, 2020, our overall generation increased slightly compared to the third quarter of 2019. For the nine months ended September 30, 2020, continued low natural gas prices have made our natural gas-fired resources relatively more economical and has significantly reduced generation from our coal-fired generation resources. The dispatch of our coal generation resources during 2020 was primarily limited to must-run and test situations due to the availability of more economical generation resources available to our members. As of September 30, 2020, the overall reduction in generation decreased both our energy revenues and expenses as described below.

Sales to Members.    We generate revenues principally from the sale of electric capacity and energy to our members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity. These revenues are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are the sales of electricity generated or purchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.

The components of member revenues for the three-month and nine-month periods ended September 30, 2020 and 2019 were as follows:

	Three Months Ended September 30,							Nine Months Ended September 30,
	(dollars in thousands)							(dollars in thousands)
	2020			2019			% Change	2020			2019			% Change
Capacity revenues	$	222,187		$	231,270		(3.9)%	$	721,836		$	712,305		1.3%
Energy revenues	143,750			151,278			(5.0)%	316,382			385,449			(17.9)%
Total	$	365,937		$	382,548		(4.3)%	$	1,038,218		$	1,097,754		(5.4)%
MWh Sales to members	7,147,341			7,137,087			0.1%	17,028,641			17,672,935			(3.6)%
Cents/kWh	5.12			5.36			(4.5)%	6.10			6.21			(1.8)%
Member energy requirements supplied	60		%	57		%	5.3%	57		%	56		%	1.8%

Energy revenues from members decreased for the three-month and nine-month periods ended September 30, 2020 compared to the same periods in 2019 primarily due to the recovery of fuel costs. For a discussion of fuel costs, which are the primary costs recovered by energy revenues, see "—Operating Expenses."

Operating Expenses

The following table summarizes our fuel costs and megawatt-hour generation by generating source.

	Cost					Generation			Cents per kWh
	(dollars in thousands)					(MWh)
	Three Months Ended September 30,					Three Months Ended September 30,			Three Months Ended September 30,
Fuel Source	2020		2019		% Change	2020	2019	% Change	2020	2019	% Change
Coal	$	29,852	$	24,095	23.9%	884,482	821,069	7.7%	3.38	2.93	15.4%
Nuclear	19,258		20,777		(7.3)%	2,459,582	2,591,374	(5.1)%	0.78	0.80	(2.5)%
Gas:
Combined Cycle	57,752		60,549		(4.6)%	3,192,130	2,898,164	10.1%	1.81	2.09	(13.4)%
Combustion Turbine	25,063		33,283		(24.7)%	807,183	987,319	(18.2)%	3.10	3.37	(8.0)%
	$	131,925	$	138,704	(4.9)%	7,343,377	7,297,926	0.6%	1.80	1.90	(5.3)%

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	Cost					Generation			Cents per kWh
	(dollars in thousands)					(MWh)
	Nine Months Ended September 30,					Nine Months Ended September 30,			Nine Months Ended September 30,
Fuel Source	2020		2019		% Change	2020	2019	% Change	2020	2019	% Change
Coal	$	34,767	$	71,209	(51.2)%	982,095	2,310,310	(57.5)%	3.54	3.08	14.9%
Nuclear	55,784		58,666		(4.9)%	7,165,407	7,355,621	(2.6)%	0.78	0.80	(2.5)%
Gas:
Combined Cycle	153,934		168,847		(8.8)%	8,071,682	7,013,337	15.1%	1.91	2.41	(20.7)%
Combustion Turbine	38,191		50,424		(24.3)%	1,261,013	1,452,213	(13.2)%	3.03	3.47	(12.7)%
	$	282,676	$	349,146	(19.0)%	17,480,197	18,131,481	(3.6)%	1.62	1.93	(16.1)%

Total fuel costs decreased for the three-month and nine-month periods ended September 30, 2020 compared to the same periods in 2019 as a result of lower natural gas prices which have significantly shifted generation from the more expensive coal-fired units. A decline in generation for the nine-month period ended September 30, 2020 compared to the same period in 2019 was primarily due to milder temperatures.

Interest charges

Allowance for debt funds used during construction increased in the three-month and nine-month periods ended September 30, 2020 as compared to the same periods of 2019 primarily due to capitalization of interest related to construction of Vogtle Units No. 3 and No. 4.

Financial Condition

Balance Sheet Analysis as of September 30, 2020

Assets

Cash and cash equivalents decreased $383.9 million, primarily due to the use of funds for general operating expenditures and quarterly debt payments during the nine-month period ended September 30, 2020.

Cash used for property additions for the nine-month period ended September 30, 2020 totaled $983.9 million. Of this amount, $816.6 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 and $45.6 million was for nuclear fuel purchases. The remainder was for expenditures related to normal additions and replacements to our existing generation facilities.

Long-term investments increased $161.6 million for the nine-month period ended September 30, 2020 primarily due to investments purchased under one of our member rate management programs. Funds collected through the rate management program are invested and held until applied to members' bills. As of September 30, 2020, total amounts invested under the program, including earnings during 2020 were approximately $114.0 million. See Note F of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs.

Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The program no longer allows additional funds to be deposited into the account. For additional information regarding restricted investments, see Note I of Notes to Unaudited Consolidated Financial Statements.

Prepayments and other current assets increased $33.5 million for the nine-month period ended September 30, 2020 primarily as a result of prepaid inventory parts to be used for future major maintenance outages.

Equity and Liabilities

Long-term debt increased $747.7 million primarily as a result of a $444.0 million advance under the Department of Energy loan guarantee, the issuance of $450 million in Series 2020 taxable first mortgage bonds and $45.9 million advanced under the Rural Utilities Service-guaranteed Federal Financing Bank loan. Offsetting these increases were amounts reclassified to long-term debt due within one year. See Note L of Notes to Unaudited Consolidated Financial Statements for additional information regarding long-term debt.

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Regulatory liabilities increased $116.2 million for the nine-month period ended September 30, 2020 primarily due to a $97.5 million increase in the deferral plan associated with one of our member rate management programs and a $21.0 million increase associated with deferred nuclear asset retirement obligations that was primarily driven by an increase in unrealized gains associated with our nuclear decommissioning investments. See Note F of Notes to Unaudited Consolidated Financial Statements for information regarding our rate management programs.

Capital Requirements and Liquidity and Sources of Capital

Vogtle Units No. 3 and No. 4

We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our 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.

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 the Georgia Public Service Commission approved in-service dates of November 2021 and November 2022, respectively. As of September 30, 2020, our total investment in the additional Vogtle units was approximately $5.7 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation.

As part of its ongoing processes, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and related test results, and workforce statistics.

The August 2018 project-level budget included an $800 million construction contingency estimate, of which our 30% interest was $240 million. As of June 30, 2020, assignments of contingency exceeded the 2018 construction contingency estimate by $75 million, of which our 30% interest was $23 million. This contingency was used to address cost risks related to construction productivity, including the April 2020 reduction in workforce designed to mitigate the impacts of the COVID-19 pandemic described below; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement, among other factors. As a result of these factors, Georgia Power established additional construction contingency of $250 million (of which our 30% interest is $75 million), as of June 30, 2020 for further potential risks, including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; additional resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. During the third quarter of 2020, approximately $10 million, of which our 30% interest is $3 million, of the construction contingency established in the second quarter of 2020 was assigned to the base capital cost forecast for cost risks primarily associated with construction productivity and field support. 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 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 September 30, 2020 for our 30% interest in the project.

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	(in millions)
	Project Budget		Actual Costs at September 30, 2020		Remaining Project Budget
Construction Costs (1)	$	5,501	$	4,536	$	965
Financing Costs	1,557		1,204		353
Total Costs	$	7,058	$	5,740	$	1,318
Project-Level Contingency	$	72	$	—	$	72
Oglethorpe-Level Contingency	370		—		370
Total Contingency	$	442	$	—	$	442
Totals	$	7,500	$	5,740	$	1,760
(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. Following peaks in April and July and subsequent declines, the number of active cases of COVID-19 at the site continues to fluctuate and impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements were not 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. Georgia Power has stated that it expects to achieve the regulatory-approved in-service dates of November 2021 and November 2022, 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 and $250 million (of which our 30% interest is $45 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.

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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 June 15, 2020, the Nuclear Regulatory Commission rejected Nuclear Watch South’s April 20, 2020 petition requesting a hearing and challenging the closure of certain inspections, tests, analyses, and acceptance criteria. On August 10, 2020, the Atomic Safety Licensing Board rejected the Blue Ridge Environmental Defense League’s May 11, 2020 petition challenging a license amendment request. The staff of the Nuclear Regulatory Commission has issued the requested amendment to the combined construction and operating license for Vogtle Unit No. 3. The Blue Ridge Environmental Defense League appealed the Atomic Safety Licensing Board’s decision to the Nuclear Regulatory Commission. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

The ultimate outcome of these matters cannot be determined at this time.

For additional information regarding Vogtle Units No. 3 and No. 4, see “Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4” in our 2019 Form 10-K. For information regarding our financing of the additional Vogtle units, see “Financing Activities—Department of Energy-Guaranteed Loans” and Note L of Notes to Unaudited Consolidated Financial Statements. See “Item 1A—RISK FACTORS” in our 2019 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units, and “Risk Factors” for a discussion of risks related to disruption to the project resulting from COVID-19.

Environmental Regulations

Federal and state laws and regulations regarding environmental matters affect operations at our facilities. On October 13, 2020, the Environmental Protection Agency (EPA) published its final 2020 Steam Electric Reconsideration Rule (2020 Reconsideration Rule). The final rule addresses EPA's revisions to its 2015 Steam Electric Power Generating Effluent Guidelines rule for flue gas desulferization and bottom ash transport. In the 2020 Reconsideration Rule, EPA revised the technology basis for treating the two waste streams and established new subcategories with varying requirements for high-flow units, low-utilization units, and units ceasing coal combustion by December 31, 2028. EPA also revised the voluntary incentives program. For units that will be subcategorized, a notice of planned participation must be provided to the state permitting authority by October 13, 2021. We are evaluating the final rule, but the ultimate impact of the rule on our operations cannot be determined at this time.

For a discussion regarding potential effects on our business from other environmental regulations, including potential capital requirements, see "Item 1—BUSINESS—REGULATION—Environmental," "Item 1A—RISK FACTORS" and "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" in our 2019 Form 10-K.

Liquidity

At September 30, 2020, we had $1.7 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $384 million in cash and cash equivalents and $1.3 billion available under our $1.8 billion of committed credit arrangements, the details of which are reflected in the table below:

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Committed Credit Facilities
	Authorized Amount		Available September 30, 2020			Expiration Date
	(dollars in millions)
Unsecured Facilities:
Syndicated Line of Credit led by CFC	$	1,210	$	808	'(1)	December 2024
CFC Line of Credit(2)	110		110			December 2023
JPMorgan Chase Line of Credit (3)	363		247			October 2021
Secured Facilities:
CFC Term Loan(2)	250		140			December 2023

(1)Of the portion of this facility that was unavailable at September 30, 2020, $266  million was dedicated to support outstanding commercial paper, and $136 million was related to letters of credit issued to support variable rate demand bonds.

(2)Any amounts drawn under the $110 million unsecured line of credit with CFC will reduce the amount that can be drawn under the $250 million secured term loan. Therefore, we reflect $140 million as the amount available under the term loan even though there are no amounts outstanding under that facility. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.

(3)Of the portion of this facility that was unavailable at September 30, 2020, $114 million related to letters of credit issued to support variable rate demand bonds and $2 million related to letters of credit issued to post collateral to third parties. We amended this credit facility in March, 2020 to increase the authorized amount from $150 million to $363 million, which is committed through the maturity of this facility in October, 2021.

We have the flexibility to use the $1.2 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters of credit and backing up commercial paper.

Under our commercial paper program, we are authorized to issue commercial paper in amounts that do not exceed the amount of our committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding.

In mid-March 2020, due to significant disruptions in the commercial paper markets, we began to borrow directly under our $1.2 billion syndicated line of credit in lieu of issuing commercial paper. As of September 30, 2020, we had repaid the borrowings under this line of credit with the proceeds of commercial paper that we were able to issue as markets stabilized.

We generally issue commercial paper to provide interim financing of our expenses related to the construction of Vogtle Units No. 3 and No. 4 which we repay with the proceeds from long-term funding sources. Our loan guaranteed by the Department of Energy is our preferred source of long-term financing of eligible costs for Vogtle Units No. 3 and No. 4, and in June 2020, we used the proceeds of a $444 million advance under this loan to repay commercial paper. See Note L of Notes to Unaudited Consolidated Financial Statements and “—Financing Activities—Department of Energy-Guaranteed Loans” for additional information regarding the Department of Energy-guaranteed loans. We also used proceeds from our $450 million first mortgage bonds to repay commercial paper.

On March 27, 2020, we amended our JPMorgan Chase line of credit, increasing the commitment from $150 million to $363 million. On March 31, 2020, we borrowed $213 million under this line of credit to purchase $212.8 million of pollution control bonds that were subject to mandatory tender on April 1, 2020. These borrowings were subsequently repaid from the proceeds of commercial paper we issued in July 2020.

Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $973 million in the aggregate, of which $508.6 million remained available at September 30, 2020. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.

Three of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At September 30, 2020, the required minimum level was $750 million and our actual patronage capital was $1.1 billion. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $14.0 billion and $4.0 billion, respectively. At September 30, 2020, we had $10.5 billion of secured indebtedness and $226.1 million of unsecured indebtedness outstanding.

At September 30, 2020, we had $540.9 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment.

Financing Activities

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First Mortgage Indenture.    At September 30, 2020, we had $10.5 billion of long-term debt outstanding under our first mortgage indenture secured equally and ratably by a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. See "Item 1—BUSINESS—OGLETHORPE POWER CORPORATION—First Mortgage Indenture" in our 2019 Form 10-K for further discussion of our first mortgage indenture.

Bond Financings. In August 2020, we issued $450 million of taxable first mortgage bonds to repay commercial paper issued to fund a portion of the cost of constructing Vogtle Units No. 3 and No. 4. In August 2020, we also remarketed the $212.8 million Series 2013 pollution control bonds which we purchased on April 1, 2020. The proceeds of this remarketing were used to repay outstanding commercial paper that had refinanced the purchase of the Series 2013 bonds. The first mortgage bonds and the notes issued in connection with the Series 2013 pollution control bonds are secured under our first mortgage indenture.

Rural Utilities Service-Guaranteed Loans.    In July 2020, we advanced the remaining $5.8 million under a $448.3 million Rural Utilities Service-guaranteed loan that was funded through the Federal Financing Bank. We have a conditional commitment on a new Rural Utilities Service-guaranteed loan totaling $630.3 million that we expect to begin advancing in early 2021. When advanced, the debt will be secured under our first mortgage indenture. As of September 30, 2020, we had $2.5 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

Department of Energy-Guaranteed Loans.   We have loans from the Federal Financing Bank guaranteed by the Department of Energy to provide funding for over $4.6 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4.

At September 30, 2020, aggregate Department of Energy-guaranteed borrowings totaled $3.5 billion, including capitalized interest. All of the debt advanced under the loan guarantee agreement is secured ratably with all other debt under our first mortgage indenture.

In accordance with the promissory notes, we began principal repayments of our Department of Energy-guaranteed loans in February 2020. As of September 30, 2020, we had repaid $59.1 million under these loans. If we fully advance these loans, we expect to repay a total of approximately $300 million in principal on these loans by November 2022. We plan to issue first mortgage bonds to refinance the principal repaid before the in-service date of Vogtle Unit No. 4.

Combined, this $4.6 billion and the $2.3 billion of debt we have raised in the capital markets represent long-term financing for more than 92% of our $7.5 billion project budget. We expect to raise long-term financing for the remaining amounts in the capital markets.

For more information regarding the loan guarantee agreement, see Note L of Notes to Unaudited Consolidated Financial Statements. For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 2019 Form 10-K.

Newly Adopted or Issued Accounting Standards

For a discussion of recently issued or adopted accounting pronouncements, see Note E of Notes to Unaudited Consolidated Financial Statements.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk

There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" in our 2019 Form 10-K.

Item 4.    Controls and Procedures

As of September 30, 2020, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective.

There have been no changes in internal control over financial reporting or other factors that occurred during the quarter ended September 30, 2020 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.

PART II—OTHER INFORMATION

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Item 1.    Legal Proceedings

There have been no material changes to the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 2019 Form 10-K.

For information about loss contingencies that could have an effect on us, see Note H to Unaudited Consolidated Financial Statements.

Item 1A.    Risk Factors

We and our members are subject to risks related to the COVID-19 pandemic, including, but not limited to, disruption to the construction of Vogtle Units No. 3 and No. 4.

The World Health Organization and Centers for Disease Control and Prevention have declared a pandemic following the outbreak of COVID-19, a respiratory disease caused by a new strain of coronavirus that is currently affecting many parts of the world, including the United States and Georgia. In response, most jurisdictions, including in the United States, have instituted restrictions on travel, public gatherings, and non-essential business operations. While some jurisdictions, including Georgia, have relaxed these restrictions, many of the restrictions remain in place and there is no guarantee that restrictions will not be reimposed. For certain periods during 2020, these restrictions significantly disrupted economic activity across the United States, including Georgia, and caused volatility in capital markets. The effects of the continued COVID-19 pandemic and related responses could include additional disruptions to capital markets, extended disruptions to supply chains and a prolonged reduction in economic activity. These effects could have a variety of adverse impacts on us and our members, including continued reduced demand for energy in our members' service territories, reduced cash flows and liquidity, reductions in investments recorded at fair value, and impairment of our ability to operate electric generation facilities, to perform necessary corporate functions and to access funds from financial institutions and capital markets. These economic disruptions could also adversely affect our members' customers' ability to pay for electric service.

Additionally, the 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. 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 announced a reduction in workforce at Vogtle Units No. 3 and No. 4, which totaled approximately 20% of the then-existing 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 reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing.Following peaks in April and July and subsequent declines, the number of active cases of COVID-19 at the site continues to fluctuate and impact productivity levels and pace of activity completion. These factors contributed to the assignment of, and increase in, construction contingency described under "Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital–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 and $250 million (of which our 30% interest is $45 to $75 million) and is included in the project budget and assumes (i) absenteeism rates continue to normalize and (ii) the intended productivity efficiencies and production targets are realized in the coming months. However, 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. The ultimate impact of the COVID-19 pandemic and the resulting economic contraction on us and our members will depend of the severity and duration of each and cannot be determined at this time.

Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds

Not Applicable.

Item 3.    Defaults upon Senior Securities

Not Applicable.

Item 4.    Mine Safety Disclosures

Not Applicable.

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Item 5.    Other Information

Not Applicable.

33

Item 6.    Exhibits

Number	Description
31.1	Rule 13a-14(a)/15d-14(a) Certification, by Michael L. Smith (Principal Executive Officer).
31.2	Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
32.1	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Michael L. Smith (Principal Executive Officer).
32.2	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).
101	XBRL Interactive Data File.
104	Cover Page Interactive Data File – (embedded within the Inline XBRL document).

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

			Oglethorpe Power Corporation (An Electric Membership Corporation)
Date:	November 12, 2020	By:	/s/ Michael L. Smith
			Michael L. Smith President and Chief Executive Officer
Date:	November 12, 2020		/s/ Elizabeth B. Higgins
			Elizabeth B. Higgins Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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