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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549


FORM 10-Q

Response to COVID-19
(Mark One)

ý

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

For the quarterly period ended September 30, 2017

OR

o

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

For the transition period from                                    to                                     
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 June 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

LOGO

opc-20200630_g1.jpg
(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 o      ☐    No ý

 ☒

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý     ☒    No o

 ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large Accelerated Filer o     ☐    Accelerated Filer o     ☐    Non-Accelerated Filerý    (Do not check if a smaller reporting company)     ☒    Smaller Reporting Company o     ☐    Emerging Growth Company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

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

 ☒

Securities registered pursuant to Section 12(b) of the Act:
Title of each class:Trading Symbol(s)Name of each exchange on which registered:
NoneN/AN/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 no0 authorized or outstanding equity securities.


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OGLETHORPE POWER CORPORATION
INDEX TO QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBERJUNE 30, 2017

2020


Page No.

Item 1.

Financial Statements


1

Unaudited Consolidated Balance Sheets as of SeptemberJune 30, 20172020 and December 31, 2016

2019

1

Unaudited Consolidated Statements of Revenues and Expenses For the Three and NineSix Months ended SeptemberJune 30, 20172020 and 2016

2019

3

Unaudited Consolidated Statements of Comprehensive Margin For the Three and Nine Months ended September 30, 2017 and 2016


4

Unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin For the NineThree and Six Months ended SeptemberJune 30, 20172020 and 2016

2019

54

Unaudited Consolidated Statements of Cash Flows For the NineSix Months ended SeptemberJune 30, 20172020 and 2016

2019

65

Notes to Unaudited Consolidated Financial Statements


76

Item 2.

Management's Discussion and Analysis of Financial Condition and Results of Operations


2523

Item 3.

Quantitative and Qualitative Disclosures About Market Risk


3730

Item 4.

Controls and Procedures


3731



Item 1.

Legal Proceedings


3831

Item 1A.

Risk Factors


3831

Item 2.

Unregistered Sales of Equity Securities and Use of Proceeds


4032

Item 3.

Defaults Upon Senior Securities


4032

Item 4.

Mine Safety Disclosures


4032

Item 5.

Other Information


4032

Item 6.

Exhibits

Exhibits


4133


4234


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CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

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

Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under "Item 1A—RISK FACTORS" and in other sections of our annual report on Form 10-K for the fiscal year ended December 31, 20162019 and under "Risk Factors" in our Form 10-Q for the quarterly period ended June 30, 2017 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 resultsduration and severity of Westinghouse Electric Company LLCthe current coronavirus ("COVID-19") pandemic and WECTEC Global Project Services Inc.'s bankruptcy filingresulting economic contraction and any inability or failure by Toshiba Corporation to perform
its obligations pursuant to its settlement agreement related to its guarantee of certain of Westinghouse's obligations related toimpact on our business, financial condition, operations, construction projects, including the additional units at Plant Vogtle;

Vogtle, and our members and their service territories;

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

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


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


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


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


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


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

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•
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;


ii
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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;


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

•
litigation or legal and administrative proceedings and settlements;

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


•
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;


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

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

•
general economic conditions;


•
weather conditions and other natural phenomena;


•
litigation or legal and administrative proceedings and settlements;

•unanticipated changes in interest rates or rates of inflation;


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


•
significant changes in critical accounting policies material to us; and


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

hazards;


•catastrophic events such as fires, earthquake, 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.
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    PART I—FINANCIAL INFORMATION

    Item 1. Financial Statements

    Oglethorpe Power Corporation
    Consolidated Balance Sheets (Unaudited)
    September
     June 30, 20172020 and December 31, 2016

    2019
    (dollars in thousands)
    20202019
    Assets  
    Electric plant:  
    In service$9,347,733  $9,209,983  
    Right-of-use assets—finance leases302,732  302,732  
    Less: Accumulated provision for depreciation(4,879,826) (4,833,025) 
    4,770,639  4,679,690  
    Nuclear fuel, at amortized cost363,140  359,270  
    Construction work in progress5,259,324  4,816,896  
    Total electric plant10,393,103  9,855,856  
    Investments and funds:
    Nuclear decommissioning trust fund509,348  511,339  
    Investment in associated companies73,972  73,318  
    Long-term investments331,000  254,864  
    Restricted investments355,340  461,757  
    Other27,194  26,422  
    Total investments and funds1,296,854  1,327,700  
    Current assets:  
    Cash and cash equivalents371,854  448,612  
    Restricted short-term investments191,599  71,833  
    Receivables266,471  166,429  
    Inventories, at average cost281,805  277,729  
    Prepayments and other current assets27,284  9,862  
    Total current assets1,139,013  974,465  
    Deferred charges:  
    Regulatory assets758,503  763,512  
    Prepayments to Georgia Power35,279  48,052  
    Other20,509  20,528  
    Total deferred charges814,291  832,092  
    Total assets$13,643,261  $12,990,113  

    		  (dollars in thousands) 

    		 

    2017 

    		 2016  

    Assets

    		       

    Electric plant:

    		       

    In service

    		 $8,857,293 $8,786,839 

    Less: Accumulated provision for depreciation

    		  (4,260,047) (4,115,339)
    ​​​ ​ ​​ ​ ​

    		  4,597,246  4,671,500 

    Nuclear fuel, at amortized cost

    		  
    360,529    		  
    377,653    		 

    Construction work in progress

    		  3,824,068  3,228,214 
    ​​​ ​ ​​ ​ ​

    Total electric plant

    		  8,781,843  8,277,367 
    ​​​ ​ ​​ ​ ​

    Investments and funds:

    		  
         		  
         		 

    Nuclear decommissioning trust fund

    		  427,786  386,029 

    Investment in associated companies

    		  74,187  72,783 

    Long-term investments

    		  125,518  99,874 

    Restricted investments

    		  265,180  221,122 

    Other

    		  21,689  20,730 
    ​​​ ​ ​​ ​ ​

    Total investments and funds

    		  914,360  800,538 
    ​​​ ​ ​​ ​ ​

    Current assets:

    		  
         		  
         		 

    Cash and cash equivalents

    		  342,064  366,290 

    Restricted short-term investments

    		  246,432  247,006 

    Receivables

    		  180,250  155,042 

    Inventories, at average cost

    		  263,226  259,831 

    Prepayments and other current assets

    		  20,438  32,919 
    ​​​ ​ ​​ ​ ​

    Total current assets

    		  1,052,410  1,061,088 
    ​​​ ​ ​​ ​ ​

    Deferred charges:

    		  
         		  
         		 

    Regulatory assets

    		  572,237  545,387 

    Other

    		  28,639  16,733 
    ​​​ ​ ​​ ​ ​

    Total deferred charges

    		  600,876  562,120 
    ​​​ ​ ​​ ​ ​

    Total assets

    		 $11,349,489 $10,701,113 
    ​​​ ​ ​​ ​​
    ​​​​​​​​
    ​​​ ​ ​​ ​ ​

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


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    Oglethorpe Power Corporation
    Consolidated Balance Sheets (Unaudited)
    September
     June 30, 20172020 and December 31, 2016

    2019
    (dollars in thousands)
    20202019
    Equity and Liabilities  
    Capitalization:  
    Patronage capital and membership fees$1,066,113  $1,016,747  
    Long-term debt9,765,244  9,403,847  
    Obligation under finance leases72,354  75,649  
    Other26,563  25,196  
    Total capitalization10,930,274  10,521,439  
    Current liabilities:
    Long-term debt and finance leases due within one year238,061  217,440  
    Short-term borrowings475,991  282,370  
    Accounts payable128,773  165,049  
    Accrued interest64,863  65,895  
    Member power bill prepayments, current74,385  77,066  
    Other current liabilities79,851  49,443  
    Total current liabilities1,061,924  857,263  
    Deferred credits and other liabilities:
    Asset retirement obligations1,094,202  1,070,640  
    Member power bill prepayments, non-current110,646  134,396  
    Regulatory liabilities407,255  364,241  
    Other38,960  42,134  
    Total deferred credits and other liabilities1,651,063  1,611,411  
    Total equity and liabilities$13,643,261  $12,990,113  

    		  (dollars in thousands) 

    		 

    2017 

    		 2016  

    Equity and Liabilities

    		       

    Capitalization:

    		  
         		  
         		 

    Patronage capital and membership fees

    		 $923,495 $859,810 

    Accumulated other comprehensive margin

    		  (352) (370)
    ​​​ ​ ​​ ​ ​

    		  923,143  859,440 

    Long-term debt

    		  
    7,991,307    		  
    7,892,836    		 

    Obligation under capital lease

    		  89,710  92,096 

    Other

    		  19,725  18,765 
    ​​​ ​ ​​ ​ ​

    Total capitalization

    		  9,023,885  8,863,137 
    ​​​ ​ ​​ ​​

    Current liabilities:

    		  
         		  
         		 

    Long-term debt and capital lease due within one year

    		  154,817  316,861 

    Short-term borrowings

    		  631,949  102,168 

    Accounts payable

    		  161,168  73,801 

    Accrued interest

    		  84,287  93,634 

    Member power bill prepayments, current

    		  43,836  176,988 

    Other current liabilities

    		  54,621  59,979 
    ​​​ ​ ​​ ​ ​

    Total current liabilities

    		  1,130,678  823,431 
    ​​​ ​ ​​ ​ ​

    Deferred credits and other liabilities:

    		  
         		  
         		 

    Asset retirement obligations

    		  726,074  698,051 

    Member power bill prepayments, non-current

    		  202,202  48,115 

    Contract retainage

    		  0  40,008 

    Regulatory liabilities

    		  236,445  197,748 

    Other

    		  30,205  30,623 
    ​​​ ​ ​​ ​ ​

    Total deferred credits and other liabilities

    		  1,194,926  1,014,545 
    ​​​ ​ ​​ ​ ​

    Total equity and liabilities

    		 $11,349,489 $10,701,113 
    ​​​ ​ ​​ ​​
    ​​​​​​​​
    ​​​ ​ ​​ ​ ​

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


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    Oglethorpe Power Corporation
    Consolidated Statements of Revenues and Expenses (Unaudited)
    For the Three and NineSix Months Ended SeptemberJune 30, 20172020 and 2016

    2019
    (dollars in thousands)
    Three MonthsSix Months
    2020201920202019
    Operating revenues:    
    Sales to Members$330,768  $358,736  $672,281  $715,206  
    Sales to non-Members176  124  337  254  
    Total operating revenues330,944  358,860  672,618  715,460  
    Operating expenses:
    Fuel79,596  111,450  150,752  210,442  
    Production93,503  105,584  209,634  208,904  
    Depreciation and amortization62,588  60,334  124,612  122,638  
    Purchased power16,334  16,635  32,947  32,699  
    Accretion13,391  13,145  26,626  23,033  
    Total operating expenses265,412  307,148  544,571  597,716  
    Operating margin65,532  51,712  128,047  117,744  
    Other income:
    Investment income11,604  14,250  24,538  30,985  
    Other1,892  (886) 3,901  942  
    Total other income13,496  13,364  28,439  31,927  
    Interest charges:
    Interest expense101,243  99,729  203,528  201,177  
    Allowance for debt funds used during construction(51,047) (46,910) (102,077) (90,337) 
    Amortization of debt discount and expense2,670  2,874  5,669  5,852  
    Net interest charges52,866  55,693  107,120  116,692  
    Net margin$26,162  $9,383  $49,366  $32,979  

    		  (dollars in thousands) 

    		 

    Three Months 

    		 

    Nine Months 

    		 

    		 2017  2016  2017  2016  

    Operating revenues:

    		             

    Sales to Members

    		 $385,758 $430,883 $1,106,975 $1,158,134 

    Sales to non-Members

    		  148  130  220  383 
    ​​​​ ​​ ​ ​​​ ​​ ​ ​

    Total operating revenues

    		  385,906  431,013  1,107,195  1,158,517 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Operating expenses:

    		             

    Fuel

    		  143,767  178,516  366,405  404,056 

    Production

    		  93,657  105,681  293,930  312,332 

    Depreciation and amortization

    		  56,143  54,719  167,983  162,606 

    Purchased power

    		  14,345  13,109  44,222  39,254 

    Accretion

    		  9,224  8,059  27,333  24,099 
    ​​​ ​ ​​ ​​​ ​ ​​ ​​

    Total operating expenses

    		  317,136  360,084  899,873  942,347 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Operating margin

    		  68,770  70,929  207,322  216,170 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Other income:

    		  
         		  
         		  
         		  
         		 

    Investment income

    		  14,850  12,578  44,509  37,628 

    Other

    		  627  1,531  1,908  6,259 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Total other income

    		  15,477  14,109  46,417  43,887 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Interest charges:

    		  
         		  
         		  
         		  
         		 

    Interest expense

    		  93,809  93,544  280,621  273,066 

    Allowance for debt funds used during construction

    		  (33,517) (30,135) (99,953) (84,460)

    Amortization of debt discount and expense          

    		  3,150  2,999  9,386  8,946 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Net interest charges

    		  63,442  66,408  190,054  197,552 
    ​​​ ​​​ ​ ​​ ​​​ ​ ​

    Net margin

    		 $20,805 $18,630 $63,685 $62,505 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​
    ​​​​​​​​​​​​​​
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

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


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    Oglethorpe Power Corporation
    Consolidated Statements of Comprehensive MarginPatronage Capital and Membership Fees (Unaudited)
    For the Three and NineSix Months Ended SeptemberJune 30, 20172020 and 2016

    2019
    (dollars in
    thousands)
    Balance at December 31, 2018$962,286 
    Net margin23,596 
    Balance at March 31, 2019$985,882 
    Net margin9,383 
    Balance at June 30, 2019$995,265 
    Balance at December 31, 2019$1,016,747 
    Net margin23,204 
    Balance at March 31, 2020$1,039,951 
    Net margin26,162 
    Balance at June 30, 2020$1,066,113 

    		  (dollars in thousands) 

    		 

    Three Months 

    		 

    Nine Months 

    		 

    		 2017  2016  2017  2016  

    Net margin

    		 
    $
    20,805    		 
    $
    18,630    		 
    $
    63,685    		 
    $
    62,505    		 
    ​​​​ ​​ ​ ​​​ ​​ ​ ​

    Other comprehensive margin:

    		  
         		  
         		  
         		  
         		 

    Unrealized gain (loss) on available-for-sale securities          

    		  56  (19) 18  358 
    ​​​ ​ ​​ ​​​ ​ ​​ ​​

    Total comprehensive margin

    		 $20,861 $18,611 $63,703 $62,863 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​
    ​​​​​​​​​​​​​​
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

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


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    Oglethorpe Power Corporation
    Consolidated Statements of Patronage Capital and Membership Fees
    and Accumulated Other Comprehensive (Deficit) MarginCash Flows (Unaudited)
    For the NineSix Months Ended SeptemberJune 30, 20172020 and 2016

    2019
    (dollars in thousands)
    20202019
    Cash flows from operating activities:  
    Net margin$49,366  $32,979  
    Adjustments to reconcile net margin to net cash provided by operating activities:
    Depreciation and amortization, including nuclear fuel$189,831  $185,318  
    Accretion cost26,626  23,033  
    Amortization of deferred gains(894) (894) 
    Allowance for equity funds used during construction(251) (427) 
    Deferred outage costs(27,507) (22,470) 
    Gain on sale of investments(11,694) (2,346) 
    Regulatory deferral of costs associated with nuclear decommissioning(5,427) (12,764) 
    Other(1,514) 1,282  
    Change in operating assets and liabilities:
    Receivables(119,414) (32,090) 
    Inventories(4,003) (15,246) 
    Prepayments and other current assets(17,423) (4,564) 
    Accounts payable(42,619) (50,361) 
    Accrued interest(1,032) 24,601  
    Accrued taxes22,469  22,916  
    Other current liabilities(15,345) (26,402) 
    Member power bill prepayments(26,431) (78,297) 
    Rate management program collections81,105  23,680  
    Total adjustments$46,477  $34,969  
    Net cash provided by operating activities$95,843  $67,948  
    Cash flows from investing activities:
    Property additions$(659,913) $(581,140) 
    Activity in nuclear decommissioning trust fund—Purchases(261,327) (180,121) 
                                                     —Proceeds257,176  176,037  
    Increase (decrease) in restricted investments(13,349) 21,667  
    Activity in other long-term investments—Purchases(180,340) (100,502) 
                 —Proceeds110,335  88,085  
    Other11,880  (2,940) 
    Net cash used in investing activities$(735,538) $(578,914) 
    Cash flows from financing activities:
    Long-term debt proceeds$1,377,089  $657,986  
    Long-term debt payments(1,000,543) (391,206) 
    Increase (decrease) in short-term borrowings, net193,620  (82,162) 
    Other(7,229) (15,714) 
    Net cash provided by financing activities$562,937  $168,904  
    Net decrease in cash and cash equivalents$(76,758) $(342,062) 
    Cash and cash equivalents at beginning of period448,612  752,618  
    Cash and cash equivalents at end of period$371,854  $410,556  
    Supplemental cash flow information:
    Cash paid for—
    Interest (net of amounts capitalized)$101,711  $85,512  
    Supplemental disclosure of non-cash investing and financing activities:
    Change in asset retirement obligations$—  $4,830  
    Accrued property additions at end of period$112,213  $108,258  
    Interest paid-in-kind$—  $35,549  
       (dollars in thousands) 

     

     
    Patronage
    Capital and
    Membership
    Fees
     
    Accumulated
    Other
    Comprehensive
    (Deficit) Margin
     
    Total
     
    Balance at December 31, 2015 $809,465 $58 $809,523 
    ​ ​​​ ​​ ​ ​​ ​ ​
    Components of comprehensive margin:          

    Net margin

    		  62,505  —  62,505 

    Unrealized gain on available-for-sale securities

    		  —  358  358 
    ​​​ ​ ​​ ​ ​​ ​​
    Balance at September 30, 2016 $871,970 $416 $872,386 
    ​ ​​​ ​​ ​ ​​ ​ ​
    ​​​​​​​​​​​
    ​ ​​ ​​​ ​ ​​​ ​

    Balance at December 31, 2016
     
    $
    859,810
     
    $
    (370
    )
    $
    859,440
     
    ​​​ ​ ​​​ ​​ ​ ​
    Components of comprehensive margin:          

    Net margin

    		  63,685  —  63,685 

    Unrealized gain on available-for-sale securities

    		  —  18  18 
    ​ ​​ ​​​ ​ ​​ ​​
    Balance at September 30, 2017 $923,495 $(352)$923,143 
    ​ ​​ ​ ​​ ​​​ ​ ​
    ​​​​​​​​​​​
    ​ ​​ ​​​ ​ ​​​ ​

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


    5

    Table of Contents

    Oglethorpe Power Corporation
    Consolidated Statements of Cash Flows (Unaudited)
    For the Nine Months Ended September 30, 2017 and 2016

    		  (dollars in thousands) 

    		 

    2017 

    		 2016  

    Cash flows from operating activities:

    		       

    Net margin

    		 $63,685 $62,505 
    ​​​ ​ ​​ ​ ​

    Adjustments to reconcile net margin to net cash provided by operating activities:

    		       

    Depreciation and amortization, including nuclear fuel

    		  279,898  268,674 

    Accretion cost

    		  27,333  24,099 

    Amortization of deferred gains

    		  (1,341) (1,341)

    Allowance for equity funds used during construction

    		  (567) (567)

    Deferred outage costs

    		  (32,777) (29,464)

    Gain on sale of investments

    		  (16,478) (653)

    Regulatory deferral of costs associated with nuclear decommissioning

    		  631  (14,522)

    Other

    		  (6,610) (4,424)

    Change in operating assets and liabilities:

    		       

    Receivables

    		  (24,650) (41,015)

    Inventories

    		  (3,395) 30,251 

    Prepayments and other current assets

    		  1,949  (1,305)

    Accounts payable

    		  68,585  (87,056)

    Accrued interest

    		  (9,347) (966)

    Accrued taxes

    		  7,249  5,348 

    Other current liabilities

    		  (13,354) (20,604)

    Member power bill prepayments

    		  20,935  32,809 
    ​​​ ​ ​​ ​​

    Total adjustments

    		  298,061  159,264 
    ​​​​ ​​ ​ ​

    Net cash provided by operating activities

    		  361,746  221,769 
    ​​​ ​ ​​ ​ ​

    Cash flows from investing activities:

    		       

    Property additions

    		  (737,146) (421,384)

    Activity in nuclear decommissioning trust fund—Purchases

    		  (329,248) (307,222)

                                                     —Proceeds

    		  323,840  302,308 

    Increase in restricted investments

    		  (44,058) (66,821)

    Decrease in restricted short-term investments

    		  574  3,519 

    Activity in other long-term investments—Purchases

    		  (45,246) (44,457)

                                                          —Proceeds

    		  27,196  35,278 

    Other

    		  (12,780) 2,401 
    ​​​ ​ ​​ ​ ​

    Net cash used in investing activities

    		  (816,868) (496,378)
    ​​​ ​ ​​ ​​

    Cash flows from financing activities:

    		       

    Long-term debt proceeds

    		  4,517  634,279 

    Long-term debt payments

    		  (240,417) (113,328)

    Increase (decrease) in short-term borrowings, net

    		  652,401  (105,225)

    Other

    		  14,395  8,553 
    ​​​ ​​​ ​ ​

    Net cash provided by financing activities

    		  430,896  424,279 
    ​​​ ​ ​​ ​​

    Net (decrease) increase in cash and cash equivalents

    		  (24,226) 149,670 

    Cash and cash equivalents at beginning of period

    		  366,290  213,038 
    ​​​ ​ ​​ ​ ​

    Cash and cash equivalents at end of period

    		 $342,064 $362,708 
    ​​​ ​ ​​ ​​
    ​​​​​​​​
    ​​​ ​ ​​ ​ ​

    Supplemental cash flow information:

    		       

    Cash paid for—

    		       

    Interest (net of amounts capitalized)

    		 $187,798 $185,484 

    Supplemental disclosure of non-cash investing and financing activities:

    		       

    Change in asset retirement obligations

    		 $2,189 $72,097 

    Change in accrued property additions

    		 $(21,904)$(24,451)

    Interest paid-in-kind

    		 $42,555 $34,587 

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


    Table of Contents

    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-monthsix-month periods ended SeptemberJune 30, 20172020 and 2016.2019. 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, 2016,2019, as filed with the SEC. The results of operations for the three-monththree- and nine-monthsix-month periods ended SeptemberJune 30, 20172020 are not necessarily indicative of results to be expected for the full year. As noted in our 20162019 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 20162019 Form 10-K.

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

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

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


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


    •
    Level 3.  Pricing inputs that include significant inputs which are generally less observable from objective sources. These inputs may include internally developed methodologies that result in management's best estimate of fair value. Level 3 financial instruments are those whose fair value is based on significant unobservable inputs. None of our financial assets or liabilities had unobservable inputs classifying them as level 3.

    Table of Contents

    1.Market approach.approach.    The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities (including a business) and deriving fair value based on these inputs.


    2.Income approach.approach.    The income approach uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

    6
    Table of Contents

    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 SeptemberJune 30, 20172020 and December 31, 2016.

    2019.
     Fair Value Measurements at Reporting Date Using  
     Quoted Prices in
    Active Markets for
    Identical Assets
     Significant Other
    Observable
    Inputs
     Significant
    Unobservable
    Inputs
    June 30, 2020(Level 1)(Level 2)(Level 3)
    (dollars in thousands)
    Nuclear decommissioning trust funds:    
    Domestic equity$162,846  $162,846  $—  $—  
    International equity trust93,046  —  93,046  —  
    Corporate bonds and debt88,181  —  88,181  —  
    US Treasury securities41,699  41,699  —  —  
    Mortgage backed securities62,873  —  62,873  —  
    Domestic mutual funds50,577  50,577  —  —  
    Municipal bonds1,398  —  1,398  —  
    Federal agency securities1,348  —  1,348  —  
    Non-US Gov't bonds & private placements1,377  —  1,377  —  
    Other6,003  6,003  —  —  
    Long-term investments:
    International equity trust23,044  —  23,044  —  
    Corporate bonds and debt27,249  —  27,249  —  
    US Treasury securities6,408  6,408  —  —  
    Mortgage backed securities12,884  —  12,884  —  
    Domestic mutual funds124,595  124,595  —  —  
    Federal agency securities1,161  —  1,161  —  
    Treasury STRIPS133,392  —  133,392  —  
    Other2,267  2,267  —  —  
    Natural gas swaps31,929  —  31,929  —  
    ​​​​​

    7
    ​​​ ​ ​​ ​ ​​ ​​

    		 

    Fair Value Measurements at Reporting Date Using 

    		 

    		  

    September 30,
    2017

    		  

    Quoted Prices in
    Active Markets for
    Identical Assets

    (Level 1)

    		  

    Significant Other
    Observable
    Inputs

    (Level 2)

    		 
    ​​​ ​ ​​ ​ ​​ ​ ​

    		  (dollars in thousands) 

    Nuclear decommissioning trust funds:

    		          

    Domestic equity

    		 $138,008 $138,008 $— 

    International equity trust

    		  81,260  —  81,260 

    Corporate bonds

    		  68,909  —  68,909 

    US Treasury and government agency securities          

    		  51,144  51,144  — 

    Agency mortgage and asset backed securities          

    		  35,153  —  35,153 

    Mutual funds

    		  47,604  47,604  — 

    Municipal bonds

    		  301  —  301 

    Other

    		  5,407  5,407  — 

    Long-term investments:

    		          

    International equity trust

    		  20,712  —  20,712 

    Corporate bonds

    		  15,173  —  15,173 

    US Treasury and government agency securities

    		  11,608  11,608  — 

    Agency mortgage and asset backed securities          

    		  1,348  —  1,348 

    Mutual funds

    		  75,479  75,479  — 

    Other

    		  1,198  1,199  — 

    Natural gas swaps

    		  807  —  807 

    		          
    ​ ​​ ​​​ ​ ​​​ ​

    Table of Contents


     
     Fair Value Measurements at Reporting Date Using  

    		 

    Fair Value Measurements at Reporting Date Using 

    		 
     Quoted Prices in
    Active Markets for
    Identical Assets
     Significant Other
    Observable
    Inputs
     Significant
    Unobservable
    Inputs

    		 

    December 31,
    2016

    		 

    Quoted Prices in
    Active Markets for
    Identical Assets

    (Level 1)

    		 

    Significant Other
    Observable
    Inputs

    (Level 2)

    		 December 31, 2019(Level 1)(Level 2)(Level 3)
    ​​ ​ ​​ ​ ​​ ​​

    		 (dollars in thousands) (dollars in thousands)

    Nuclear decommissioning trust funds:

    		       Nuclear decommissioning trust funds:    

    Domestic equity

    		 $170,408 $170,408 $— Domestic equity$179,346  $179,346  $—  $—  

    International equity trust

    		 66,861 — 66,861 International equity trust96,204  —  96,204  —  

    Corporate bonds

    		 60,019 — 60,019 

    US Treasury and government agency securities

    		 65,725 65,725 — 

    Agency mortgage and asset backed securities

    		 17,410 — 17,410 
    Corporate bonds and debtCorporate bonds and debt63,849  —  63,849  —  
    US Treasury securitiesUS Treasury securities45,522  45,522  —  —  
    Mortgage backed securitiesMortgage backed securities62,400  —  62,400  —  
    Domestic mutual fundsDomestic mutual funds55,522  55,522  —  —  

    Municipal bonds

    		 943 — 943 Municipal bonds1,189  —  1,189  —  
    Federal agency securitiesFederal agency securities2,586  —  2,586  —  

    Other

    		 4,663 4,663 — Other4,721  4,450  271  —  

    Long-term investments:

    		       Long-term investments:

    Corporate bonds

    		 11,853 — 11,853 

    US Treasury and government agency securities

    		 12,187 12,187 — 

    Agency mortgage and asset backed securities

    		 1,651 — 1,651 

    International equity trust

    		 15,946 — 15,946 International equity trust23,161  —  23,161  —  

    Mutual funds

    		 57,932 57,932 — 
    Corporate bonds and debtCorporate bonds and debt20,395  —  20,395  —  
    US Treasury securitiesUS Treasury securities9,257  9,257  —  —  
    Mortgage backed securitiesMortgage backed securities12,867  —  12,867  —  
    Domestic mutual fundsDomestic mutual funds126,380  126,380  —  —  
    Federal agency securitiesFederal agency securities1,082  —  1,082  —  
    Treasury STRIPSTreasury STRIPS59,816  —  59,816  —  

    Other

    		 305 305 — Other1,906  1,906  —  —  

    Natural gas swaps

    		 (15,090) — (15,090)Natural gas swaps32,256  —  32,256  —  

    		 
    ​ ​​ ​​​ ​ ​​ ​​​​​​
    follows:
    20202019
    Carrying
    Value    		Fair
    Value    		Carrying
    Value    		Fair
    Value
    ​(in thousands)
    Long-term debtLong-term debt$10,105,932  $12,893,268  $9,726,428  $11,180,658  
    ​ ​​ ​ ​​ ​ ​​ ​​ ​ ​​​​​​

    		 

    2017

    		 

    2016

    		 
    ​​ ​​​ ​ ​​​ ​​ ​ ​

    		  Carrying
    Value    		 Fair
    Value    		 Carrying
    Value    		 Fair
    Value
    		 
    ​​ ​ ​​ ​​​ ​ ​​ ​

    Long-term debt

    		 $8,237,972 $9,119,700 $8,304,523 $9,043,029 

    		 
    ​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    8

    Table of Contents

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

    value because of the liquid nature of the deposits with the U.S. Treasury.
    (C)
    Derivative Instruments.    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management.    We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. Our risk management and compliance committee provides general oversight over all derivative activities. We do not apply hedge accounting for any of these derivatives,to derivative transactions, but instead apply regulatoryregulated operations accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps are reflected as regulatory assets or liabilities, as appropriate.
    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 SeptemberJune 30, 20172020, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

    We have entered into International Swaps and Derivatives Association agreements with our natural gas hedge counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral, termination and netting (which, in certain cases, allows us to use the net value of affected transactions with the same counterparty in the event of default by the counterparty or early termination of the agreement).

    Additionally, we have implemented procedures to monitor the creditworthiness of our counterparties and to evaluate nonperformance in valuing counterparty positions. We have contracted with a third party to assist in monitoring certain of our counterparties' credit standing and condition. Net liability positions are generally not adjusted as we use derivative transactions as hedges and have the ability and intent to perform under each of our contracts. In the instance of net asset positions, we consider general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

    The contractual agreements contain provisions that could require us or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit ratings from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty.

    Gas hedges.    

    Under the natural gas swap arrangements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment.


    Table of Contents

    9
    Table of Contents
    ​ ​​ ​ ​

    Year

    		  

    Natural Gas Swaps
    (MMBTUs)
    (in millions)

    		 
    ​ ​​ ​ ​

    2017

    		  3.8 

    2018

    		  24.6 

    2019

    		  18.7 

    2020

    		  15.9 

    2021

    		  12.9 

    2022

    		  5.8 
    ​​​ ​ ​

    Total

    		  81.7 
    ​ ​​ ​ ​
    Year
     Natural Gas Swaps
    (MMBTUs)
     (in millions)
    202017.0  
    202125.6  
    202218.3  
    202314.4  
    202413.2  
    202510.2  
    Total98.7  
    2019.
    ​​ ​​ ​ ​​ ​ ​

    		 

    Balance Sheet
    Location

    		  

    Fair Value

    		 
    ​​ ​​ ​​​ ​ ​

    		    2017 2016 

    		 

     

    		  

    (dollars in thousands)

    		 
     Balance Sheet
    Location
    		Fair Value

    Not designated as hedges:

    		        
     20202019
     (dollars in thousands)

    Assets:

    		        Assets:   

    Natural gas swaps

    		 Other current assets $3,302 $13,833 Natural gas swapsOther current assets$—  $—  

    Natural gas swaps

    		 Other deferred charges $— $3,289 

    Liabilities:

    		 

     

    		  
         		 
         		 Liabilities:   

    Natural gas swaps

    		 Other current liabilities $— $54 Natural gas swapsOther current liabilities$15,359  $12,898  

    Natural gas swaps

    		 Other deferred credits $4,109 $1,977 Natural gas swapsOther deferred credits$16,570  $19,358  
    ​​ ​​ ​ ​​ ​ ​

    Table of Contents

    2019.
    ​ ​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​

    		 Statement of
    Revenues and
    Expenses
    Location    		  Three months
    ended
    September 30,    		  Nine months
    ended
    September 30,    		 

    		    

    2017

    		  

    2016

    		  

    2017

    		  

    2016

    		 
    ​ ​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​

    		    (dollars in thousands) 

    Not Designated as hedges:

    		               

    Natural Gas Swaps

    		 Fuel $778 $2,039 $3,514 $2,057 

    Natural Gas Swaps

    		 Fuel  (678) (5,923) (1,495) (18,262)
    ​​​​​ ​ ​​ ​ ​​ ​​​ ​ ​

    		   $100 $(3,884)$2,019 $(16,205)
    ​​​​​ ​​​ ​ ​​ ​ ​​ ​ ​
    ​​​​​​​​​​​​​​​​
    ​​​​​ ​ ​​ ​​​ ​ ​​​ ​

    		               
    ​​​ ​​ ​ ​​ ​ ​​ ​ ​​ ​​
    Statement of
    Revenues and
    Expenses
    Location    		Three Months Ended
    June 30,    		Six Months Ended
    June 30,
     2020201920202019
     (dollars in thousands)
    Natural Gas Swaps gainsFuel$—  $11  $—  $224  
    Natural Gas Swaps lossesFuel(7,141) (1,126) (11,593) (1,799) 
    Total $(7,141) $(1,115) $(11,593) $(1,575) 
    ​​​ ​​ ​ ​​ ​ ​

    		 

    Balance Sheet
    Location

    		  

    2017

    		  

    2016

    		 
    ​ ​​ ​​ ​ ​​ ​​

    		    (dollars in thousands) 

    Not designated as hedges:

    		         

    Natural gas swaps

    		 Regulatory asset $(2,788)$(62)

    Natural gas swaps

    		 Regulatory liability  1,981  15,152 

    Interest rate options

    		 Regulatory asset  —  (5,788)
    ​​​​​ ​ ​​ ​ ​

    Total not designated as hedges

    		   $(807)$9,302 
    ​​​​​ ​​​ ​ ​
    ​​​​​​​​​​
    ​​​​​ ​​​ ​ ​

    		         
    ​​​ ​​ ​​​ ​ ​
    (D)
    Investments in Debt and EquityInvestment Securities.    Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carriedrecorded at marketfair value within the accompanying consolidated balance sheets. We apply regulated operations accounting to the unrealized gains and losses net of any tax effect, added to or deducted from other comprehensive margin, except that, in accordance with our rate-making treatment, unrealized gains and losses fromall investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset for asset retirement obligations. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset.securities. All realized and unrealized gains and losses are determined using the specific identification method. AsAt June 30, 2020, investments with a fair value of September 30, 2017$11,271,000 were in an unrealized loss position for greater than one year and represented approximately 79%68% of theseour gross unrealized losses, had beenwhile investments with a fair value of $45,247,000 were in an unrealized loss position for a duration of less than one year.

    2019.
    ​ ​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    		  

    Gross Unrealized

    		 
    ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    		  (dollars in thousands) 

    September 30, 2017

    		  Cost  Gains  Losses  Fair
    Value    		 
    ​​​ ​​​ ​ ​​ ​ ​​ ​ ​

    Equity

    		 $251,021 $75,181 $(4,386)$321,816 

    Debt

    		  224,458  2,194  (1,769) 224,883 

    Other

    		  6,604  1  —  6,605 
    ​​​ ​​​ ​ ​​ ​ ​​ ​ ​

    Total

    		 $482,083 $77,376 $(6,155)$553,304 
    ​​​ ​ ​​ ​ ​​ ​​​ ​ ​
    Gross Unrealized
    (dollars in thousands)
    June 30, 2020CostGainsLossesFair
    Value
    Equity$256,741  $125,801  $(11,151) $371,391  
    Debt440,600  21,243  (1,146) 460,697  
    Other8,270  —  (10) 8,260  
    Total$705,611  $147,044  $(12,307) $840,348  


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    Gross Unrealized
    (dollars in thousands)
    December 31, 2019CostGainsLossesFair
    Value
    Equity$258,870  $144,832  $(5,990) $397,712  
    Debt354,535  8,474  (874) 362,135  
    Other6,356  —  —  6,356  
    Total$619,761  $153,306  $(6,864) $766,203  

    ​ ​​ ​​​ ​ ​​​ ​​ ​ ​

    		  

    Gross Unrealized

    		 
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​

    		  (dollars in thousands) 

    December 31, 2016

    		  Cost  Gains  Losses  Fair
    Value    		 
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​

    Equity

    		 $237,317 $51,054 $(5,041)$283,330 

    Debt

    		  201,492  1,167  (3,423) 199,236 

    Other

    		  3,339  —  (2) 3,337 
    ​ ​​ ​​​ ​ ​​​ ​​ ​ ​

    Total

    		 $442,148 $52,221 $(8,466)$485,903 
    ​ ​​ ​ ​​ ​​​ ​ ​​ ​​
    (E)
    Recently Issued or Adopted Accounting Pronouncements.   In May 2014,June 2016, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard was effective for the annual reporting period beginning after December 15, 2016 using either of the following transition methods: (i) a full retrospective approach reflecting the application of the standard in each prior reporting period with the option to elect certain practical expedients, or (ii) a modified retrospective approach with the cumulative effect of initially adopting the standard recognized at the date of adoption (which includes additional footnote disclosures). Early adoption was not permitted.

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    (F)
    Accumulated Comprehensive Margin.    The table below provides detail of the beginning and ending balance for each classification of other comprehensive margin along with the amount of any reclassification adjustments included in margin for each of the periods presented in the unaudited Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive (Deficit) Margin. There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in our 2016
    nonlease components.

    ClassificationJune 30, 2020December 31, 2019
    (dollars in thousands)
    Right-of-Use Assets—Finance leases  
    Right-of-use assets$302,732  $302,732  
    Less: Accumulated provision for depreciation(260,139) (257,504) 
    Total finance lease assets$42,593  $45,228  
    Lease liabilities—Finance leases
    Obligations under finance leases$72,354  $75,649  
    Long-term debt and finance leases due within one year6,418  6,081  
    Total finance lease liabilities$78,772  $81,730  


    ClassificationJune 30, 2020December 31, 2019
    (dollars in thousands)
    Right-of-Use Assets—Operating leases  
    Electric plant in service$3,795  $3,237  
    Total operating lease assets$3,795  $3,237  
    Lease liabilities—Operating leases
    Capitalization—Other$2,889  $2,293  
    Other current liabilities1,001  1,252  
    Total operating lease liabilities$3,890  $3,545  

     Three months endedSix months ended
    Lease CostClassificationJune 30, 2020June 30, 2019June 30, 2020June 30, 2019
     (dollars in thousands)
    Finance lease cost:     
    Amortization of leased assetsDepreciation and amortization$1,344  $1,189  $2,688  $2,378  
    Interest on lease liabilitiesInterest expense2,217  2,372  4,434  4,744  
    Operating lease cost:
    Inventory(1) & production expense
    		272  883  795  1,766  
        Total leased cost $3,833  $4,444  $7,917  $8,888  

    14
    Table of Contents

    (1) The majority of our operating lease costs relates to net marginour railcar leases and such costs are added to the cost of our fossil-fuel inventories and are recognized in fuel expense as the table belowinventories are reflected in "Other income" onconsumed.
    June 30, 2020December 31, 2019
    Lease Term and Discount Rate:  
    Weighted-average remaining lease term (in years)  
    Finance leases8.598.84
    Operating leases7.347.39
    Weighted-average discount rate:
    Finance leases11.05 %11.05 %
    Operating leases4.62 %5.12 %

    Six months ended
    June 30, 2020June 30, 2019
    (dollars in thousands)
    Other Information:  
    Cash paid for amounts included in the measurement of lease liabilities  
    Operating cash flows from finance leases$4,516  $—  
    Operating cash flows from operating leases$950  $1,840  
    Financing cash flows from finance leases$2,959  $—  
    Right-of-use assets obtained in exchange for new operating lease liabilities$1,227  $6,983  
    Maturity analysis of our unaudited Consolidated Statementsfinance and operating lease liabilities as of RevenuesJune 30, 2020 is a follows:
    (dollars in thousands)
    Year Ending December 31,Finance LeasesOperating LeasesTotal
    2020$7,475  $612  $8,087  
    202114,949  1,121  16,070  
    202214,949  930  15,879  
    202314,949  709  15,658  
    202414,949  235  15,184  
    Thereafter55,533  1,085  56,618  
    Total lease payments$122,804  $4,692  $127,496  
    Less: imputed interest(44,032) (802) (44,834) 
    Present value of lease liabilities$78,772  $3,890  $82,662  
    As a lessor, we primarily lease office space to several tenants within our headquarters building. Several of these tenants are related parties. We account for all of these lease agreements as operating leases.
    Lease income recognized during the three and Expenses.

    Our effective tax rate is zero; therefore, all amounts below are presented net of tax.

    six months ended June 30, 2020 and June 30, 2019 was as follows:
    ​ ​​ ​ ​

    		  Accumulated Other
    Comprehensive
    (Deficit) Margin    		 

    		  

    Three Months Ended
    September 30, 2016

    		 
    ​​​ ​ ​

    		  

    (dollars in thousands)

    		 

    		  

    Available-for-sale
    Securities

    		 
    ​​​​ ​

    Balance at June 30, 2016

    		 $435 

    Unrealized gain

    		  
    50    		 

    (Gain) reclassified to net margin

    		  
    (69
    )
    ​​​ ​ ​

    Balance at September 30, 2016

    		 $416 
    ​​​ ​ ​
    Three Months Ended June 30,Six Months Ended June 30,
    2020201920202019
    (dollars in thousands)
    Lease income$1,542  $1,522  $3,090  $3,040  



    		  Three Months Ended
    September 30, 2017    		 
    ​​​ ​ ​

    		  

    (dollars in thousands)

    		 

    		  

    Available-for-sale
    Securities

    		 
    ​​​​ ​

    Balance at June 30, 2017

    		 
    $
    (408
    )

    Unrealized gain

    		  
    33    		 

    Loss reclassified to net margin

    		  
    23    		 
    ​​​ ​ ​

    Balance at September 30, 2017

    		 $(352)
    ​​​ ​ ​

    		    
    ​​​ ​ ​

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    ​ ​​ ​ ​

    		  Nine Months Ended
    September 30, 2016    		 
    ​​​ ​ ​

    		  

    (dollars in thousands)

    		 

    		  

    Available-for-sale
    Securities

    		 
    ​​​ ​ ​

    Balance at December 31, 2015

    		 
    $
    58    		 

    Unrealized gain

    		  
    486    		 

    (Gain) reclassified to net margin

    		  
    (128
    )
    ​​​ ​ ​

    Balance at September 30, 2016

    		 $416 
    ​​​ ​ ​


    		  Nine Months Ended
    September 30, 2017    		 
    ​​​ ​ ​

    		  

    (dollars in thousands)

    		 

    		  

    Available-for-sale
    Securities

    		 
    ​​​​ ​

    Balance at December 31, 2016

    		 
    $
    (370
    )

    Unrealized loss

    		  
    (57
    )

    Loss reclassified to net margin

    		  
    75    		 
    ​​​ ​ ​

    Balance at September 30, 2017

    		 $(352)
    ​​​ ​ ​

    		    
    ​​​ ​ ​
    (G)
    (H)Contingencies and Regulatory Matters.
    15
    Table of Appeals upheld the Superior Court of DeKalb County's decision to dismiss on all counts both of the cases described under Note 12—Patronage Capital Litigation in our 2016 Form 10-K. The plaintiffs did not further appeal these dismissals to the Georgia Supreme Court and the appeal period has since expired, ending this litigation.

    b.    Contents

    Environmental Matters

    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 aremay also become subject to climate change regulations that impose restrictions on emissions of greenhouse gases, including carbon dioxide, for certain new and modified facilities.

    In general, these and other types of environmental requirements have become increasingly stringent. dioxide.

    Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future


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

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

    (H)
    On July 29, 2020, a group of individual plaintiffs filed a complaint in the Superior Court of Fulton County, Georgia against Georgia Power alleging that releases from Plant Scherer, of which we are a co-owner, have impacted groundwater, surface water, and air, resulting in alleged personal injuries and property damage. 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.Account that are held by the U.S. Treasury, acting through the Federal Financing Bank. We can only utilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank debt service payments. The funds on deposit currently earn interest at a rate of 5% per annum. Beginning October 1, 2020, deposits will earn interest at 4% per annum and beginning October 1, 2021, the rates will be set at the 1-year floating treasury rate. The program no longer allows additional funds to be deposited into the account. At SeptemberJune 30, 20172020 and December 31, 2016,2019, we had restricted investments totaling $511,612,000$546,939,000 and $468,179,000,$533,590,000, respectively, of which $265,180,000$355,340,000 and $221,122,000,$461,757,000, respectively, were classified as long-term. The funds on deposit with the Rural Utilities Service in the Cushion of Credit Account are held by the U.S. Treasury, acting through the Federal Financing Bank.
    (I)
    (J)Regulatory Assets and Liabilities.    We apply the accounting guidance for regulated operations. Regulatory assets represent certain costs that are probable of recovery through future rates. We expect to recover such costs from our members in future revenues through rates under the wholesale power contracts we have with each of our members extendingmembers. The wholesale power contracts extend through December 31, 2050. Regulatory liabilities represent certain items of income that we are retaining and that will be applied in the future to reduce revenues required to be recovered from our members.


    16
    Table of Contents

    The following regulatory assets and liabilities are reflected on the unaudited consolidated balance sheets as of SeptemberJune 30, 20172020 and December 31, 2016.

    2019.
    ​ ​​ ​ ​​ ​​

    		 

    2017

    		 

    2016

    		 

    		 

    (dollars in thousands)

    		 20202019
    ​ ​​ ​ ​​ ​​​(dollars in thousands)

    Regulatory Assets:

    		     Regulatory Assets:  

    Premium and loss on reacquired debt(a)

    		 $51,546 $55,084 

    Amortization on capital leases(b)

    		 33,454 32,274 

    Outage costs(c)

    		 42,060 39,986 

    Interest rate swap termination fees(d)

    		 2,231 3,570 

    Asset retirement obligations—Ashpond and other(l)

    		 59,540 33,747 

    Depreciation expense(e)

    		 43,023 44,091 

    Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(f)

    		 47,322 43,444 

    Interest rate options cost(g)

    		 110,915 107,394 

    Deferral of effects on net margin—Smith Energy Facility(h)

    		 167,941 172,399 

    Other regulatory assets(m)

    		 14,205 13,398 
    ​​ ​ ​​ ​​
    Premium and loss on reacquired debt(a)Premium and loss on reacquired debt(a)$37,624  $40,067  
    Amortization of financing leases(b)Amortization of financing leases(b)35,381  35,433  
    Outage costs(c)Outage costs(c)43,093  34,367  
    Asset retirement obligations—Ashpond and other(k)Asset retirement obligations—Ashpond and other(k)236,834  245,932  
    Depreciation expense(d)Depreciation expense(d)39,108  39,820  
    Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e)Deferred charges related to Vogtle Units No. 3 and No. 4 training costs(e)54,113  53,466  
    Interest rate options cost(f)Interest rate options cost(f)124,444  121,938  
    Deferral of effects on net margin—Smith Energy Facility(g)Deferral of effects on net margin—Smith Energy Facility(g)151,592  154,564  
    Other regulatory assets(m)Other regulatory assets(m)36,314  37,925  

    Total Regulatory Assets

    		 $572,237 $545,387 Total Regulatory Assets$758,503  $763,512  

    Regulatory Liabilities:

    		 
         		 
         		 Regulatory Liabilities:

    Accumulated retirement costs for other obligations(i)

    		 $14,235 $9,829 

    Deferral of effects on net margin—Hawk Road Energy Facility(h)

    		 19,705 20,163 

    Major maintenance reserve(j)

    		 43,269 28,379 

    Amortization on capital leases(b)

    		 20,780 23,084 

    Deferred debt service adder(k)

    		 93,296 86,082 

    Asset retirement obligations(l)

    		 40,199 11,766 

    Other regulatory liabilities(m)

    		 4,961 18,445 
    ​​ ​ ​​ ​ ​
    Accumulated retirement costs for other obligations(h)Accumulated retirement costs for other obligations(h)$18,343  $12,692  
    Deferral of effects on net margin—Hawk Road Energy Facility(g)Deferral of effects on net margin—Hawk Road Energy Facility(g)18,177  18,485  
    Major maintenance reserve(i)Major maintenance reserve(i)41,768  50,144  
    Amortization of financing leases(b)Amortization of financing leases(b)12,806  14,256  
    Deferred debt service adder(j)Deferred debt service adder(j)119,115  114,453  
    Asset retirement obligations—Nuclear(k)Asset retirement obligations—Nuclear(k)38,711  61,516  
    Revenue deferral plan(l)Revenue deferral plan(l)155,117  90,066  
    Other regulatory liabilities(m)Other regulatory liabilities(m)3,218  2,629  

    Total Regulatory Liabilities

    		 $236,445 $197,748 Total Regulatory Liabilities$407,255  $364,241  
    ​​ ​ ​​ ​ ​

    Net Regulatory Assets

    		 $335,792 $347,639 Net Regulatory Assets$351,248  $399,271  
    ​​ ​ ​​ ​ ​
    ​​​​​
    ​​ ​ ​​ ​ ​

    		 
    ​ ​​ ​​​ ​ ​
    (a)
    Represents premiums paid, together with unamortized transaction costs related to reacquired debt that are being amortized over the lives of the refunding debt, which range up to 2724 years.

    (b)
    Represents the difference between expense recognized for rate-making purposes andversus financial statement purposes related to capitalfinance lease payments and the aggregate of the amortization of the asset and interest on the obligation.

    (c)
    Consists of both coal-fired maintenance and nuclear refueling outage costs. Coal-fired outage costs are amortized on a straight-line basis to expense over a 24-month period.periods up to 60 months, depending on the operating cycle of each unit. Nuclear refueling outage costs are amortized on a straight-line basis to expense over the 18 toor 24-month operating cycles of each unit.

    (d)
    Represents losses on settled interest rate swap arrangements that are being amortized through the end of 2018.

    (e)
    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 Plant Vogtlethe 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.

    (f)
    (e)Deferred charges consist of training related to Vogtle Units No. 3costs, including interest and No. 4 training and interest related carrying costs of such training. Amortization will commence effective with the commercial operation date of each unit and amortized to expense over the life of the units.

    (g)
    (f)Deferral of costs associated withpremiums paid to purchase interest rate options purchasedused to hedge interest rates on certain borrowings, related tocarrying costs and other incidentals associated with construction of Vogtle Units No.3No. 3 and No.4 construction thatNo. 4. Amortization will be amortized over the life of the associated debt.

    (h)
    commence when Vogtle Unit No. 3 goes in-service, which is expected November 2021.
    (g)Effects on net margin for Smith and Hawk Road Energy Facilities were deferred through the end of 2015 and are being amortized over the remaining life of each respective plant.

    (i)
    (h)Represents the accrual of retirement costs associated with long-lived assets for which there are no legal obligations to retire the assets.

    (j)
    (i)Represents collections for future major maintenance costs; revenues are recognized as major maintenance costs are incurred.

    (k)
    (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.

    (l)
    (k)Represents the difference in the timing of recognition of thedecommissioning costs of decommissioning for financial statement purposes versus ratemaking purposes, as well as the deferral of unrealized gains and losses of funds set aside for ratemaking purposes.

    decommissioning.
    (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 periodperiods for other regulatory assets range up to 3330 years and the amortization periodperiods of other regulatory liabilities range up to 107 years.


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    (J)
    (K)Member Power Bill Prepayments.    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through January 2022,December 2024, with the majority of the balance scheduled to be credited by the end of 2019.
    (K)
    2020.
    (L)Debt.

    17
    Table of Contents

    a)
    Department of Energy Loan Guarantee:

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    (L)
    issuances.
    (M)Vogtle Units No. 3 and No. 4 Construction Project.   We, Georgia Power, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia, acting by and through its Board of Water, Light and Sinking Fund Commissioners, doing business as Dalton Utilities (collectively, the Co-owners) are parties to an Ownership Participation Agreement that, along with other agreements, governs our participation in two2 additional nuclear units under construction at Plant Vogtle, Units No. 3 and No. 4. The Co-owners appointed Georgia Power to act as agent under this agreement. Our binding ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement,
    19
    Table of Contents
    Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

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    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.

    22

    Table of Contents

    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 2/3 of our members' sales are to residential customers. For the second quarter of 2020, our preliminary analysis indicates that the impact of the COVID-19 pandemic reduced our members' overall energy demand by approximately two to three percent compared to the same quarter of 2019. 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 impacted the fair value of certain of our investments and our ability to issue commercial paper for certain periods of 2020 as discussed further herein. 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 provided throughout "Management's Discussion and Analysis of Financial Condition and Results of Operations" and in "Risk Factors."
    Results of Operations

    For the Three and Six Months Ended June 30, 2020 and 2019

    For the Three and Nine Months Ended September 30, 2017 and 2016

    Net Margin

    Our net margins for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 were $20.8$26.2 million and $63.7$49.4 million, respectively, compared to $18.6$9.4 million and $62.5$33.0 million for the same periods of 2016. Through September2019. For the six-months ended June 30, 2017, we collected2020, our net margin was approximately 123%88% of our targeted net margin of $51.7$56.1 million for the year ending December 31, 2017. These collections are typical as our capacity revenues are generally recorded evenly throughout the year and our management budgets conservatively.2020. In September 2017,June 2020, our board of directors approved a budget adjustment that reduced revenue requirementsrevision which will reduce revenues $6.5 million by $5.0 million in order to provide our members with a measure of relief for costs they incurred as a result of significant system damage from Hurricane Irma.year-end. We anticipate our board of directors will approve an additionalanother budget adjustment by theyear end of the year so that margins will achieve, but not exceed, our 2017the 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 $5.9 million and $4.5 million as of June 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 20162019 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 June 30, 2020, our overall generation was lower primarily due to milder summer weather compared to the second quarter of 2019. Continued low natural gas prices have made our natural gas-fired resources relatively more economical and led to an increase in generation from these resources which has significantly reduced generation from our coal-fired generation resources. For the six months ended June 30, 2020, the dispatch of our coal generation resources was primarily limited to must-run and test situations due to the availability of more economical generation resources available to our members. 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, andelectricity. These revenues are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin. Energy revenues are earned by sellingthe sales of electricity to our members, which involves generatinggenerated or purchasing electricitypurchased for our members. Energy revenues recover the variable costs of our business, including fuel, purchased energy and variable operation and maintenance expense.


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    The components of member revenues for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 and 20162019 were as follows:

    Three Months Ended
    June 30,    		Six Months Ended
    June 30,
    (dollars in thousands) (dollars in thousands) 
    20202019% Change20202019% Change
    Capacity revenues$240,256  $235,049  2.2%$499,649  $481,035  3.9%
    Energy revenues90,512  123,687  (26.8)%172,632  234,171  (26.3)%
    Total$330,768  $358,736  (7.8)%$672,281  $715,206  (6.0)%
    MWh Sales to members5,338,468  5,837,713  (8.6)%9,881,300  10,535,848  (6.2)%
    Cents/kWh6.20  6.15  0.8%6.80  6.79  0.1%
    Member energy requirements supplied59 %59 %0.0%55 %56 %(1.8)%
     
    		  
    		  
    		  
    		  
    		  
    		  
    		 
    ​​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​​ ​ ​

    		  Three Months Ended
    September 30,    		  2017 vs.
    2016
    % Change    		  Nine Months Ended
    September 30,    		  2017 vs.
    2016
    % Change
    		 
    ​​​ ​​​ ​ ​​ ​​​ ​ ​​​ ​​ ​ ​

    		  (dollars in thousands)     (dollars in thousands)    

    		  

    2017

    		  

    2016

    		  

     

    		  

    2017

    		  

    2016

    		    
    ​​​ ​​​ ​ ​​​​​ ​ ​​ ​ ​​​​

    Capacity revenues

    		 $217,918 $228,011  (4.4%) $666,226 $681,384  (2.2%) 

    Energy revenues

    		  167,840  202,872  (17.3%)  440,749  476,750  (7.6%) 
    ​​​ ​ ​​ ​ ​​​​​​ ​​ ​ ​​​​

    Total

    		 $385,758 $430,883  (10.5%) $1,106,975 $1,158,134  (4.4%) 
    ​​​ ​ ​​ ​ ​​​​​​ ​​ ​ ​​​​
    ​​​​​​​​​​​​​​​​​​​​
    ​​​​ ​​ ​ ​​​​​ ​ ​​ ​ ​​​​

    MWh Sales to members

    		  6,962,978  7,956,412  (12.5%)  18,213,379  19,886,944  (8.4%) 

    Cents/kWh

    		  5.54  5.42  2.3%  6.08  5.82  4.4% 

    Member energy requirements supplied

    		  
    62
    %    		 
    64
    %    		 

    (3.9%)

    		  
    63
    %    		 
    64
    %    		 

    (1.3%)

    		 
    ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    Capacity revenues for the three-month and nine-month periods ended September 30, 2017 reflect a $5.0 million reduction in revenue requirements for the September 2017 budget adjustment approved by the board of directors discussed above.

    Energy revenues from members decreased for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 compared to the same periods in 20162019 primarily due to a decrease inthe recovery of fuel costs which was largely a result of a decrease in generation for member sales in 2017.costs. For a discussion of fuel costs, which are the primary components ofcosts recovered by energy revenues, see "—Operating Expenses."


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    Operating Expenses

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

    CostGenerationCents per kWh
    (dollars in thousands)(MWh)   
     Three Months Ended
    June 30,
     Three Months Ended
    June 30,
     Three Months Ended
    June 30,
    Fuel Source20202019% Change20202019% Change20202019% Change
    Coal$3,513  $26,057  (86.5)%75,247  825,171  (90.9)%4.67  3.16  47.8%
    Nuclear19,772  20,743  (4.7)%2,538,129  2,616,214  (3.0)%0.78  0.79  (1.3)%
    Gas:       
    Combined Cycle45,955  49,267  (6.7)%2,523,734  2,114,879  19.3%1.82  2.33  (21.9)%
    Combustion Turbine10,356  15,383  (32.7)%349,794  428,422  (18.4)%2.96  3.59  (17.5)%
    $79,596  $111,450  (28.6)%5,486,904  5,984,686  (8.3)%1.45  1.86  (22.0)%
    24
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    ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​

    		  Cost  Generation  Cents per kWh
    		 
    ​​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​

    		  (dollars in thousands)  (MWh)          

    		  

    Three Months Ended
    September 30,

    		  

    2017 vs.

    		  

    Three Months Ended
    September 30,

    		  

    2017 vs.

    		  

    Three Months Ended
    September 30,

    		  

    2017 vs.

    		 
    ​​​ ​ ​​ ​​​​​​ ​ ​​ ​ ​​​​​ ​ ​​ ​ ​​​​

    Fuel Source

    		  2017  2016  2016
    % Change    		  2017  2016  2016
    % Change    		  2017  2016  2016
    % Change
    		 
    ​​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​

    Coal

    		 $30,924 $49,478  (37.5%)  1,157,960  1,704,203  (32.1%)  2.67  2.90  (8.0%) 

    Nuclear

    		  23,249  21,950  5.9%  2,585,668  2,691,129  (3.9%)  0.90  0.82  10.2% 

    Gas:

    		                            

    Combined Cycle

    		  67,058  73,223  (8.4%)  2,888,612  2,976,562  (3.0%)  2.32  2.46  (5.6%) 

    Combustion Turbine

    		  22,536  33,865  (33.5%)  544,294  846,699  (35.7%)  4.14  4.00  3.5% 
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    		 $143,767 $178,516  (19.5%)  7,176,534  8,218,593  (12.7%)  2.00  2.17  (7.8%) 
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​
    ​​​​​​​​​​​​​​​​​​​​​​​​​​​​​
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​



    CostGenerationCents per kWh
    (dollars in thousands)(MWh)   
     Six Months Ended
    June 30,
     Six Months Ended
    June 30,
     Six Months Ended
    June 30,
    Fuel Source20202019%
    Change    		20202019%
    Change    		20202019%
    Change
    Coal$4,916  $47,114  (89.6)%97,613  1,489,241  (93.4)%5.04  3.16  59.5%
    Nuclear36,526  37,889  (3.6)%4,705,825  4,764,247  (1.2)%0.78  0.80  (2.5)%
    Gas:       
    Combined Cycle96,182  108,298  (11.2)%4,879,552  4,115,173  18.6%1.97  2.63  (25.1)%
    Combustion Turbine13,128  17,141  (23.4)%453,830  464,894  (2.4)%2.89  3.69  (21.7)%
    $150,752  $210,442  (28.4)%10,136,820  10,833,555  (6.4)%1.49  1.94  (23.2)%

    		  Cost  Generation  Cents per kWh
    		 
    ​​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​

    		  (dollars in thousands)  (MWh)          

    		  

    Nine Months Ended
    September 30,

    		  

    2017 vs.

    		  

    Nine Months Ended
    September 30,

    		  

    2017 vs.

    		  

    Nine Months Ended
    September 30,

    		  

    2017 vs.

    		 
    ​​​ ​ ​​ ​​​​​​ ​ ​​ ​ ​​​​​ ​ ​​ ​ ​​​​

    Fuel Source

    		  2017  2016  2016
    % Change    		  2017  2016  2016
    % Change    		  2017  2016  2016
    % Change
    		 
    ​​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​

    Coal

    		 $81,867 $114,961  (28.8%)  2,913,161  3,945,663  (26.2%)  2.81  2.91  (3.5%) 

    Nuclear

    		  66,538  61,786  7.7%  7,399,354  7,605,266  (2.7%)  0.90  0.81  10.7% 

    Gas:

    		                            

    Combined Cycle

    		  181,254  165,272  9.7%  7,546,775  7,338,407  2.8%  2.40  2.25  6.6% 

    Combustion Turbine

    		  36,746  62,037  (40.8%)  881,514  1,644,184  (46.4%)  4.17  3.77  10.5% 
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    		 $366,405 $404,056  (9.3%)  18,740,804  20,533,520  (8.7%)  1.96  1.97  (0.6%) 
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​
    ​​​​​​​​​​​​​​​​​​​​​​​​​​​​​
    ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​ ​ ​​ ​ ​​ ​ ​

    		                            
    ​ ​​ ​​​ ​ ​​​ ​​ ​ ​​ ​ ​​ ​​​ ​ ​​​ ​​ ​ ​

    Total fuel costs decreased for the three-month and nine-monthsix-month periods ended SeptemberJune 30, 20172020 compared to the same periods in 2019 as a result of lower natural gas prices, including a shift in generation to relatively more economical natural gas-fired units, as well as a decline in generation. The decrease in generation for the three-month period ended June 30, 2020 compared to the same period in 2019 was primarily due to milder temperatures.

    Production costs decreased for the three-month period ended June 30, 2020 compared to the same period in 2019 primarily due to lower fixed operational and maintenance costs at our nuclear plants. Production costs remained relatively unchanged for the comparable six-month periods.
    Interest charges
    Allowance for debt funds used during construction increased in the three-month and six-month periods ended June 30, 2020 as compared to the same periods of 20162019 primarily due to a decrease in generationcapitalization of interest related to construction of Vogtle Units No. 3 and No. 4.
    Financial Condition
    Balance Sheet Analysis as a result of moderate temperatures. In addition, generationJune 30, 2020
    Assets
    Cash and cash equivalents decreased $76.8 million, primarily due to the use of funds for general operating expenditures and quarterly debt payments during the nine-monthsix-month period ended SeptemberJune 30, 2017 compared to the same period of 2016 was somewhat affected by increased natural gas prices and planned maintenance outages during 2017.

    Financial Condition

    2020.

    Balance Sheet Analysis as of September 30, 2017

    Assets

    Cash used for property additions for the nine-monthsix-month period ended SeptemberJune 30, 20172020 totaled $737.1$659.9 million. Of this amount, approximately $518.5$547.6 million was associated with construction expenditures for Vogtle Units No. 3 and No. 4 $47.7and $39.6 million was for nuclear fuel purchases andpurchases. The remainder was for expenditures forrelated to normal additions and replacements to our existing generation facilities.

    Long-term investments increased $76.1 million for the six-month period ended June 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 June 30, 2020, total amounts invested under the program during 2020 were approximately $70.3 million. See Note F of Notes to Unaudited Consolidated Financial Statements for a discussion of our member rate management programs.
    Restricted investments consist of funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The funds, including interest earned thereon,We can only be applied to debt service on ourutilize these investments for future Rural Utilities Service-guaranteed Federal Financing Bank notes. Decisionsdebt service payments. The program no longer allows additional funds to be deposited into the account. For additional information regarding whenrestricted investments, see Note I of Notes to applyUnaudited Consolidated Financial Statements.
    Receivables increased $100.0 million for the funds are guided by the interest rate environment and our anticipated liquidity needs.


    Table of Contents

    Equity and Liabilities

    Long-term debt increased $98.5 million during the nine-monthsix-month period ended SeptemberJune 30, 20172020 primarily due to the classificationtiming of $122.6 millionmember payments. As a precautionary response to the potential impact of commercial paper as long-term debt. In October 2017, $122.6 millionthe COVID-19 pandemic, in March 2020, we extended the payment cycle for member billings through July 2020 by up to fourteen days to provide our members with additional flexibility. All of tax-exempt bonds was issuedour members have continued to refund the commercial paper on a long-term basis. For information regarding the refundingpay all amounts billed in accordance with this extended schedule.

    Equity and Liabilities
    25
    Table of commercial paper and the issuance of tax-exempt bonds, see Note K.

    Contents

    Long-term debt increased $361.4 million primarily as a result of a $444.0 million advance under the Department of Energy loan guarantee and capital leasesa $40.1 million advance under the Rural Utilities Service-guaranteed Federal Financing Bank. Offsetting these increases were amounts reclassified to long-term debt due within one year decreased $162.0 million during the nine-month period ended September 30, 2017. The decrease was primarily dueyear. See Note L of Notes to the redemption of $122.6 million of variable rate pollution control revenue bonds through the issuance of commercial paper in January 2017. In addition, the decrease was due to certain quarterly Federal Financing Bank note payments we made, when due, in early January 2017.

    Unaudited Consolidated Financial Statements for additional information regarding long-term debt.

    Short-term borrowings, which primarily provide interim financing for Vogtle Units No. 3 and No. 4 construction costs, increased $529.8$193.6 million during the nine-monthsix-month period ended SeptemberJune 30, 2017.

    Accounts payable2020. Total borrowings were $1.2 billion and repayments during the period totaled $956.4 million.

    Regulatory liabilities increased $87.4$43.0 million for the nine-monthsix-month period ended SeptemberJune 30, 20172020 primarily asdue to a result of a $104.7$65.1 million increase in the payable to Georgia Power Company for operation and maintenance costs for our co-owned plants and capital costsdeferral plan associated with Vogtle Units No. 3 and No. 4.one of our member rate management programs. Offsetting the increase was $17.2a $22.8 million decrease associated with deferred nuclear asset retirement obligations that was primarily driven by a decrease in credits applied tounrealized gains associated with our members' bills in the first quarter of 2017, for a board approved reduction in 2016 revenue requirements as a result of margins in excess of our 2016 target.

    The current portion of member power bill prepayments decreased $133.2 million for the nine-month period ended September 30, 2017 due to the application of credits against the power bills of members that participate in the power bill prepayment program. The long-term portion of member power bill prepayments increased $154.1 million for the nine-month period ended September 30, 2017 due to member contributions to the program made during the third quarter of 2017. For additional information on the member power bill prepayment program, seenuclear decommissioning investments. See Note JF of Notes to Unaudited Consolidated Financial Statements.

    Statements for information regarding our rate management programs.
    Capital Requirements and Liquidity and Sources of Capital

    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 binding ownership interest and proportionate share of the cost to construct these units is 30%. Pursuant to this agreement, Georgia Power has designated Southern Nuclear Operating Company, Inc. as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

    In 2008, Georgia Power, acting

    Our current budget for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc. (collectively, the EPC Contractor). Stone & Webster was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (WECTEC). Pursuant to the EPC Agreement, the EPC Contractor agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle.


    Table of Contents

    Under the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments. The EPC Agreement also provided for liquidated damages upon the EPC Contractor's failure to fulfill the schedule and certain performance guarantees, each subject to an aggregate cap of 10% of the contract price, or approximately $920 million.

    Toshiba Corporation guaranteed certain payment obligations of the EPC Contractor under the EPC Agreement (the Toshiba Guarantee), including any liability of the EPC Contractor for abandonment of work. In January 2016, Westinghouse delivered to the Co-owners $920 million of letters of credit from financial institutions (Westinghouse Letters of Credit) to secure a portion of the EPC Contractor's potential obligations under the EPC Agreement. The Westinghouse Letters of Credit are subject to annual renewals through June 30, 2020, and require 60 days' written notice to Georgia Power, as agent of the Co-owners,our 30% ownership interest in the event the Westinghouse Letters of Credit will not be renewed.

    Under the terms of the EPC Agreement, the EPC Contractor did not have the right to terminate the EPC Agreement for convenience. In the event of an abandonment of work by the EPC Contractor, the maximum liability of the EPC Contractor under the EPC Agreement was 40% of the contract price, or $3.68 billion, of which our proportionate share is approximately $1.1 billion.

    On March 29, 2017, the EPC Contractor filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. To provide for a continuation of work at Vogtle Units No. 3 and No. 4 is $7.5 billion, which includes capital costs, allowance for funds used during construction, our allocation of the project-level contingency and a separate Oglethorpe-level contingency, and is based on November 2021 and November 2022 commercial operation dates, respectively. As of June 30, 2020, our total investment in the additional Vogtle units was approximately $5.5 billion. We and some of our members have implemented various rate management programs to lessen the impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation. The Georgia Public Service Commission approved in-service dates for Vogtle Units No. 3 and No. 4 are November 2021 and November 2022, respectively.

    As part of its ongoing process, Southern Nuclear continues to evaluate cost and schedule forecasts on a regular basis to incorporate current information available, particularly in the areas of engineering support, commodity installation, system turnovers and workforce statistics.
    The August 2018 project-level budget included an $800 million construction contingency estimate, of which our 30% interest was $240 million. During the second quarter of 2020, approximately $425 million of construction contingency, of which our 30% interest was $128 million, was assigned to the base capital cost forecast for cost risks including, among other things, construction productivity, including the April 2020 reduction in workforce designed to mitigate the impacts of the COVID-19 pandemic described below, field support, subcontracts, engineering resources and procurement. When combined with prior assignments of construction contingency, the second quarter 2020 assignment of contingency exceeded the remaining balance of the $800 million contingency by approximately $75 million, of which our 30% interest was $23 million. Through June 30, 2020, assignments of contingency for cost risks also have included, among other factors, construction productivity; craft labor incentives; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. As a result of these factors, Southern Nuclear established additional construction contingency of $250 million (of which our 30% interest is $75 million) for further potential risks, including, among other factors, construction productivity and expected impacts of the COVID-19 pandemic; adding resources for supervision, field support, project management, initial test program, start-up, and operations and engineering support; subcontracts; and procurement. Georgia Power has stated its expectation to allocate the remainder of this project-level contingency by completion of the project.
    The project-level contingency is separate and in addition to our Oglethorpe-level contingency. The assignment of project-level contingency through June 30, 2020 and our $75 million share of the additional project-level contingency reduced the amount of our Oglethorpe-level contingency but did not change our current $7.5 billion budget. After taking into account the increase of project-level contingency, our remaining Oglethorpe-level contingency is $325 million. The Oglethorpe-level contingency, which we have carried at various levels since the beginning of the project, was designed to cover potential cost, schedule, and financing risks associated with our share of the project which may not be covered by project-level contingencies. As construction progresses, the Oglethorpe-level contingency may continue to fluctuate as it represents the difference between
    26
    Table of Contents
    known project-level costs and contingencies and our total budget of $7.5 billion. At the end of the project, if there is remaining Oglethorpe-level contingency, we will adjust our project budget to remove this contingency and bill our members based on the actual project costs. The table below shows our project budget and actual costs through June 30, 2020 for our 30% interest in the project.
    (in millions)
    Project Budget           Actual Costs at June 30, 2020Remaining Project Budget
    Construction Costs (1)
    		$5,524  $4,303  $1,221  
    Financing Costs1,576  1,151  425  
       Total Costs$7,100  $5,454  $1,646  
    Project-Level Contingency$75  $—  $75  
    Oglethorpe-Level Contingency325  —  325  
       Total Contingency$400  $—  $400  
    Totals$7,500  $5,454  $2,046  
    (1) Construction costs are net of $1.1 billion received from Toshiba Corporation under a Guarantee Settlement Agreement.
    In mid-March 2020, Southern Nuclear began implementing policies and procedures designed to mitigate the risk of transmission of COVID-19 at the construction site, including worker distancing measures, isolating individuals who have tested positive for COVID-19, are showing symptoms consistent with COVID-19, are being tested for COVID-19, or have been in close contact with such persons, requiring self-quarantine, and adopting additional precautionary measures.
    In April 2020, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreementannounced 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 EPC Contractorrecommendations from the Centers for Disease Control and WECTEC Staffing Services LLC, whichPrevention. The April 2020 workforce reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the bankruptcy court approved on March 30, 2017. The Interim Assessment Agreement provided, among other items, thatinitial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to impact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the termlevels 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 Interim Assessment Agreement Georgia Power was obligatedunits by their regulatory-approved in-service dates. In July 2020, Southern Nuclear updated its cost and schedule forecast, and indicated that it still expects to pay,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 behalfnew 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 Co-owners, all costs accrued by the EPC Contractor for subcontractorsCOVID-19 pandemic could further disrupt or delay construction, testing, supervisory, and vendors for services performed or goods provided. The Interim Assessment Agreement, as amended, expired on July 27, 2017.

    Subsequent to the EPC Contractor's bankruptcy filing, a number of subcontractors to the EPC Contractor, including Fluor Enterprises, Inc., a subsidiary of Fluor Corporation, alleged non-payment by the EPC Contractor for amounts owed for work performed onsupport activities at Vogtle Units No. 3 and No. 4. Georgia Power, acting for itselfThe incremental cost associated with COVID-19 mitigation actions and as agent for the Co-owners, has taken,impacts on construction productivity is currently estimated to be between $150 and continues to take, actions to remove liens filed by these subcontractors through the posting of surety bonds. Georgia Power estimates the aggregate liability, through September 30, 2017, of the Co-owners for the removal of subcontractor liens and payment of other EPC Contractor pre-petition accounts payable to total approximately $386$250 million of(of which our proportionate share totals approximately $115 million. As of September 30, 2017, $340 million of this aggregate liability had been paid or accrued by Georgia Power, on behalf of30% interest is $45 to $75 million) and is included in the Co-owners.

    On June 9, 2017, Georgia Powerproject budget and assumes (i) absenteeism rates normalize and (ii) the other Co-owners and Toshiba entered into a settlement agreement regarding the Toshiba Guarantee (the Guarantee Settlement Agreement). Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the amount of its obligation under the Toshiba Guarantee is $3.68 billion (the Guarantee Obligations), of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), it will hold a portion of such payments in trust for the Co-owners and promptly pay them as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising certain remedies, including drawing on the Westinghouse Letters of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the

    intended

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    balance

    productivity efficiencies and production targets are realized in the coming months. The ultimate impact of the Guarantee Obligations will become immediately due and payable, and the Co-owners may exercise any and all rights and remedies, including drawingCOVID-19 pandemic on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date. In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Execution of any such transaction cannot be assured and would require certain consents from and cooperation by the Department of Energy.

    On November 9, 2017, Toshiba released its financial results for the second quarter of the fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of September 30, 2017. Toshiba also reiterated the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.

    Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and the EPC Contractor entered into a services agreement, which was amended and restated on July 20, 2017 (the Services Agreement), for the EPC Contractor to transition construction management of Vogtle Units No. 3 and No. 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved the EPC Contractor's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement. The Services Agreement became effective upon approval by the Department of Energy on July 27, 2017 and will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.

    On August 31, 2017, Georgia Power filed its 17th Vogtle Construction Monitoring report (VCM 17 Report) with the Georgia Public Service Commission. In the VCM 17 Report, Georgia Power recommended that construction on Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager. The recommendation to continue construction is supported by all the Co-owners and is based on the results of a comprehensive schedule, cost-to-complete and cancellation assessment. The Georgia Public Service Commission is expected to render a decision on these matters by February 6, 2018.

    The revised project schedule Georgia Power submitted to the Georgia Public Service Commission for approval included commercial operation dates of November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Based on comprehensive cost-to complete assessments and the revised commercial operation dates, our revised project budget is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget assumes 100% recovery of our $1.1 billion share of the Guarantee Obligations from Toshiba. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion without taking into account any amounts recoverable from Toshiba. Amounts recovered in connection with the Guarantee Settlement Agreement will be recorded as a reduction to the construction work in progress balance as payments are received.


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    Based on the revised project schedule and budget the following table provides an updated estimate of our forecasted capital expenditures related to Vogtle Units No. 3 and No. 4 for 2017 through 2019 (dollars in millions).

     
    		  
    		  
    		  
    		  
    		 
    ​​​ ​ ​​ ​ ​​ ​​​ ​ ​

    		  2017  2018  2019  Total
    		 
    ​​​ ​​​ ​ ​​ ​​​ ​ ​

    Future Generation

    		 $645 $677 $504 $1,826 
    ​ ​​ ​ ​​ ​​​ ​ ​​ ​​

    In addition to the amounts reflected in the table above, we have budgeted approximately $1.9 billion to complete construction of Vogtle Units No. 3 and No. 4 beyond the years shown in the table. These projected capital expenditures assume that Toshiba fully performs its obligations under the Guarantee Settlement Agreement and the failure of Toshiba to perform those obligations could have a material impact on our costs for Vogtle Units No. 3 and No. 4. For additional information regarding our capital expenditures, see "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Financial Condition—Capital Requirements—Capital Expenditures" in our 2016 Form 10-K.

    Effective October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement (the Bechtel Agreement) with Bechtel Power Corporation, whereby Bechtel will serve as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4. Facility design and engineering remains the responsibility of Westinghouse under the Services Agreement. The Bechtel Agreement is a cost reimbursable plus fee arrangement, whereby Bechtel will be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally (not jointly) liable for its proportionate share, based on its ownership interest, of all amounts owed to Bechtel 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 at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including, certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events.

    On November 2, 2017, the Co-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba or, except in the case in which each of the Co-owners has assigned its rights under the Guarantee Settlement Agreement to a third party, a material breach by Toshiba of the Guarantee Settlement Agreement; (ii) termination or rejection in bankruptcy of certain agreements, including the Services Agreement or the Bechtel Agreement; (iii) the Georgia Public Service Commission or Georgia Power determines that any of Georgia Power's costs relating to the construction of Vogtle Units No. 3 and No. 4 will not be recovered in retail rates because such costs are deemed unreasonable or imprudent; or (iv) an increase in the construction budget contained in the seventeenth VCM report of more than $1 billion or extension of the project schedule contained in the seventeenth VCM report of more than one year. In addition, pursuant to the Joint Ownership Agreements, the required approval of holders of ownership interests in Vogtle Units No. 3 and No. 4 is at least (i) 90% for a change of the primary construction contractor and (ii) 67% for material amendments to the Services Agreement or agreements with Southern Nuclear or the primary construction contractor, including the Bechtel Agreement.


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    The effectiveness of the amendments to the Joint Ownership Agreements related to the Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement, dated as of April 21, 2006, as amended, is subject to the condition that we obtain the approval of the Rural Utilities Service as required under our loan contract with the Rural Utilities Service.

    In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.

    We have a $3.06 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.72 billion as of September 30, 2017. Pursuant to the terms of the Loan Guarantee Agreement, no further advances are permitted pending satisfaction of certain conditions, including approval of the Bechtel Agreement and an amendment to the Loan Guarantee Agreement. The timing of satisfaction of these conditions is currently uncertain but likely to be satisfied in 2018. On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to approximately $1.62 billion in additional guaranteed loans under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions. For additional information regarding conditions for future advances, potential repayment over a five-year period, covenants and events of default under the Loan Guarantee Agreement with the Department of Energy, see Note K of Notes to Unaudited Consolidated Financial Statements and for additional information regarding the financing of Vogtle Units No. 3 and No. 4, see "Financing Activities—Department of Energy-Guaranteed Loan." We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances.

    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 as construction proceeds.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 resolutionsubmittal by Southern Nuclear of Inspections, Tests, Analyses,inspections, tests, analyses, and Acceptance Criteriaacceptance 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, if construction proceeds, which may result in additional license amendments or require other resolution. On May 11, 2020, the Blue Ridge Environmental Defense League filed a petition with the Nuclear Regulatory Commission that challenges a license amendment request. On June 15, 2020, the Nuclear Regulatory Commission issued an appealable order rejecting Nuclear Watch South's April 20, 2020 petition requesting a hearing and challenging the closure of certain inspections, tests, analyses, and acceptance criteria. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs.

    As construction continues,costs to the risk remains that challenges with management of contractors, subcontractors and vendors, labor productivity, fabrication, delivery, assembly, and installation of plant systems, structures, and components, or other issues could arise and may further impact project schedule and cost.

    Co-owners.

    The ultimate outcome of these matters cannot be determined at this time. See "Risk Factors" in this Form 10-Q for risks related to
    For additional information regarding Vogtle Units No. 3 and No. 4, see "Item 1—BUSINESS—OUR POWER SUPPLY RESOURCES—Future Power Resources—Plant Vogtle Units No. 3 and No. 4" in our 2019 Form 10-K. For information regarding our financing of the Guarantee Settlement Agreementadditional 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 20162019 Form 10-K for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.


    Tableunits, and "Risk Factors" for a discussion of Contents

    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. Following are some substantial developments relating to environmental regulations and litigation that have occurred since we filed our Form 10-Q for the quarterly period ended June 30, 2017.

    On October 10, 2017, the U.S. Environmental Protection Agency (EPA) proposedFor a rule to repeal the Clean Power Plan in its entirety on the basis that the Clean Power Plan exceeds the EPA's authority under the Clean Air Act. Even though some portions of the rule may be in accord with the Clean Air Act, EPA proposes to find that those portions are not severable from the objectionable portions and that the entire Clean Power Plan be repealed. EPA will decide what action, if any, to take in the future with regard to any replacement Clean Power Plan and has stated that it intends to issue an advanced notice of proposed rulemaking in the near future to solicit information on alternate systems to reduce greenhouse gas emissions consistent with its authority under the Clean Air Act. We cannot predict the outcome of this current proposal or any litigation that might be brought challenging any resulting final rule, nor can we predict the outcome of the litigation currently pending on the existing Clean Power Plan.

    In September 2017, EPA postponed certain compliance dates for its November 2015 rule for the effluent limitations guidelines and standards for the steam electric power generating (ELG Rule) for two years. Plants Scherer and Wansley are regulated under this rule. EPA has stated that it intends to conduct a rulemaking to potentially revise the more stringent best available technology economically achievable effluent limitations and pretreatment standards for existing sources for flue gas desulfurization wastewater and bottom ash transport water established in the ELG Rule; however, it does not intend to revise the ELG Rule for fly ash transport, flue gas mercury control wastewater or other requirements. We cannot predict the outcome of any actions EPA may take to revise the ELG Rule, or any litigation that might be brought challenging any final rule.

    We continue to evaluate all EPA actions regarding reviews and reconsiderations of final rules and processing of proposed rules and cannot predict the outcome of these rulemakings, any related state rulemakings or any related litigation, including litigation that might be brought to challenge the issuance of replacement or new final rules. It is unknown what impact potential rule changes will have on our and our members' operations. Continued uncertainty related to the status of current and future environmental regulations may make long-term planning decisions more difficult.

    For further 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 20162019 Form 10-K10-K.

    Current Market Conditions
    In March and "Item 2—Management's Discussion And Analysis OfApril 2020, the financial markets experienced a temporary disruption due to the COVID-19 pandemic. While the U.S. banking system remains sufficiently capitalized, credit and other financial markets in the U.S. and globally suffered substantial stress, volatility, illiquidity and disruption as a result of the economic uncertainty stemming from the pandemic. In the second quarter, financial markets began to improve significantly due to the Federal Reserve's significant easing of monetary policy, and Congress's passage of a series of broad economic stimulus packages.
    Starting in mid-March 2020, the commercial paper markets saw significant disruptions, with A-2/P-2 commercial paper issuers unable to reliably access the market or able to do so only at significantly higher cost. As a result, we utilized other available sources of liquidity during this period. Following this initial disruption, market conditions have stabilized, and we have resumed issuing commercial paper as our primary source of short-term financing.
    Obtaining favorable financing is important to our business due to, among other things, our significant capital needs to maintain existing electric generation facilities, comply with environmental requirements and regulations, and complete the construction of Vogtle Units No. 3 and No. 4. Future disruptions in the credit markets could make it more challenging or more expensive to carry out our financing objectives in the near term. See "—Liquidity" and "—Financing Activities" below for more information about our short-term and long-term financing needs.
    Nuclear Decommissioning Funds
    We maintain external and internal funds to fund our share of certain costs associated with the decommissioning of our co-owned nuclear plants. The allocation of equity and fixed income securities in these funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the fair value of funds is exposed to price fluctuations in equity markets and changes in interest rates. We actively monitor the investment performance of the funds and periodically review asset allocation in accordance with our nuclear decommissioning fund investment policy.
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    With the rebound in the financial markets in the second quarter of 2020, the fair value of our nuclear decommissioning funds, both external and internal, recovered to year-end 2019 levels after having declined by 13% in the first quarter of the year as a result of market conditions due to the COVID-19 pandemic. The year-to-date increase as of June 30, 2020, is 0.1%. For additional information regarding our nuclear decommissioning funds, see Note 1(i) in Notes to Consolidated Financial Condition And Results Of Operations—Financial Condition—Capital Requirements and Liquidity and Sources of Capital—Environmental Regulations"Statements in our quarterly reports on2019 Form 10-Q for the quarterly periods ended March 31, 2017 and10-K.
    Liquidity
    At June 30, 2017.

    Liquidity

    At September 30, 2017,2020, we had $1.07$1.3 billion of unrestricted available liquidity to meet our short-term cash needs and liquidity requirements. This amount included $342$372 million in cash and cash equivalents and $726$882 million of unused and available committed credit arrangements.


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    At September 30, 2017, we had $1.61under our $1.8 billion of committed credit arrangements, in place, the details of which are reflected in the table below:

    Committed Credit Facilities
    Authorized
    Amount    		Available
    June 30, 2020    		 Expiration
    Date
    (dollars in millions)  
    Unsecured Facilities:    
    Syndicated Line of Credit led by CFC$1,210  $598  
    '(1)
    		December 2024
      CFC Line of Credit(2)
    		110  110   December 2023
    JPMorgan Chase Line of Credit (3)
    		363  34  October 2021
    Secured Facilities:    
      CFC Term Loan(2)
    		250  140  December 2023
    ​​​ ​ ​​​ ​​

    Committed Credit Facilities

    ​​​ ​ ​​ ​ ​​

    		  

    Authorized
    Amount

    		  

    Available
    October 13, 2017

    		 

    Expiration Date

    ​ ​​ ​​​ ​ ​​

    		  (dollars in millions)  

    Unsecured Facilities:

    		        

    Syndicated Line of Credit led by CFC

    		 $1,210 $442(1)March 2020

    CFC Line of Credit(2)

    		  110  110 December 2018

    JPMorgan Chase Line of Credit

    		  150  34(3)October 2018

    Secured Facilities:

    		  
         		  
         		 

     

    CFC Term Loan(2)

    		  250  140(2)December 2018
    ​ ​​ ​ ​​ ​​​

    Total

    		 $1,610 $726  
    ​ ​​ ​​​ ​ ​​
    (1)
    Of the portion of this facility that was unavailable at October 13, 2017, $632June 30, 2020, $476  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 have been borrowedoutstanding under that facility. Any amounts borrowed under the $250 million term loan would be secured under our first mortgage indenture, with a maturity no later than December 31, 2043.

    (3)
    Of the portion of this facility that was unavailable at October 13, 2017,June 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.

    Currently, we are primarily using our commercial paper program to provide interim funding for payments related to the construction of Vogtle Units No. 3parties and No. 4 prior to receiving advances of long-term funding$213 million was drawn under the Departmentcredit facility. 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 Energy-guaranteed Federal Financing Bank loan. See Note Kthis facility in October, 2021. We plan to keep the authorized amount of Notes$363 million in place through December, 2020, and then will consider reducing it to Unaudited Consolidated Financial Statements$150 million in January, 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 "—Department of Energy-Guaranteed Loan" for a discussion of recent amendments that were made to the Loan Guarantee Agreement with the Department of Energy which restricts our ability to request further loan advances pending a determination to continue construction of the additional Vogtle units and satisfaction of related conditions, including an amendment to the Loan Guarantee Agreement. Our last advance under this loan was received in December 2016 and timing regarding our ability to make further advances under this loan is uncertain but likely in 2018. The inability to advance funds under our Department of Energy loan has reduced our available liquidity in 2017. We expect this constraint to be mitigated in the coming months through one or more of several potential options including resumption of advances under the Department of Energy loan, monetization of the Toshiba Guarantee Settlement Agreement, or issuance of taxable bonds.

    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. Our
    In mid-March 2020, due to significant disruptions in the commercial paper programmarkets, we began to borrow directly under our $1.2 billion syndicated line of credit in lieu of issuing commercial paper. As of June 30, 2020, we had repaid the borrowings under this line of credit with the proceeds of commercial paper 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 currently sized at $1.0 billion.

    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.

    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. As of June 30, 2020, these borrowings remained outstanding; however we subsequently repaid these borrowings 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 $760$973 million in the aggregate, of which $509$508.6 million remained available at SeptemberJune 30, 2017.2020. 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
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    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.


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    TwoThree of our credit facilities contain a financial covenant that requires us to maintain minimum levels of patronage capital. At SeptemberJune 30, 2017,2020, the required minimum level was $675$750 million and our actual patronage capital was $923 million.$1.0 billion. These agreements contain an additional covenant that limits our secured indebtedness and unsecured indebtedness, both as defined in the credit agreements, to $12.0$14.0 billion and $4.0 billion, respectively. At SeptemberJune 30, 2017,2020, we had $8.1$9.9 billion of secured indebtedness and $756$689.0 million of unsecured indebtedness outstanding.

    At SeptemberJune 30, 2017,2020, we had $512$546.9 million on deposit in the Rural Utilities Service Cushion of Credit Account, all of which is classified as a restricted investment. See "—Balance Sheet Analysis as of September 30, 2017—Assets" for more information regarding this account.

    Financing Activities

    First Mortgage Indenture.    At SeptemberJune 30, 2017,2020, we had $8.1$9.9 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 20162019 Form 10-K for further discussion of our first mortgage indenture.

    Bond Financings. In the third quarter of 2020, we plan to issue approximately $450 million of taxable first mortgage bonds for the purpose of repaying outstanding commercial paper issued in connection with funding a portion of the cost of constructing Vogtle Units No. 3 and No. 4. Additionally, in the third quarter of 2020 we plan to remarket the $212.8 million Series 2013 pollution control bonds which we purchased on April 1, 2020. The proceeds of this remarketing will be used to repay outstanding commercial paper that was used to refinance the purchase of the Series 2013 bonds. The first mortgage bonds and the notes issued in connection with the Series 2013 pollution control bonds will be secured under our first mortgage indenture.
    Rural Utilities Service-Guaranteed Loans.    At SeptemberJune 30, 2017,2020, we had twoone approved Rural Utilities Service-guaranteed loansloan being funded through the Federal Financing Bank totaling $448.3 million that are in various stages of being drawn down. These two loans totaled $678 million with $501had $5.8 million remaining to be advanced. In July 2020 we advanced the remaining $5.8 million under this loan. We also have a conditional commitment on a 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 SeptemberJune 30, 2017,2020, we had $2.5 billion of debt outstanding under various Rural Utilities Service-guaranteed loans.

    Department of Energy-Guaranteed Loan.    In 2014, we closed on a loan withLoans.   We have loans from the Federal Financing Bank guaranteed by the Department of Energy that will fund up to the lesserprovide funding for over $4.6 billion of $3.06 billion or 70% of eligible project costs related to the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. This loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by theAt June 30, 2020, aggregate Department of Energy.

    As of September 30, 2017, we had advanced $1.72Energy-guaranteed borrowings totaled $3.4 billion, under this loan and had $1.34 billion remaining to be advanced.including capitalized interest. All of the debt advanced under thisthe loan will beguarantee agreement is secured ratably with all other debt under our first mortgage indenture. Access

    In accordance with the promissory notes, we began principal repayments of our Department of Energy-guaranteed loans in February 2020. As of June 30, 2020, we have repaid $34.1 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 committed funds underscheduled principal repayments made before the in-service date of Vogtle Unit No. 4.
    Combined, this loan requires us to meet certain conditions related to our business$4.6 billion and the Vogtle$1.9 billion of debt we have raised in the capital markets represent long-term financing for more than 85% of our $7.5 billion project and also requires certain third-parties relatedbudget. We expect to raise long-term financing for the Vogtle project to comply with certain laws. Seeremaining amounts in the capital markets.
    For more information regarding the loan guarantee agreement, see Note KL of Notes to Unaudited Consolidated Financial Statements for a discussion of recent amendments that were made to the Loan Guarantee Agreement with the Department of Energy which restrict our ability to request further loan advances pending a determination to continue construction of the additional Vogtle units and satisfaction of related conditions, including an amendment to the Loan Guaranty Agreement. Our last advance under this loan was received in December 2016 and timing regarding our ability to make further advances under this facility is uncertain. Under certain circumstances, including a decision not to continue construction of the Vogtle units, the Department of Energy has discretion to require that we repay all amounts outstanding under the loan over a five-year period.

    On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.62 billion in additional guaranteed funding under the Loan Guarantee Agreement. Final approval and issuance of these additional loan guarantees by the Department of Energy cannot be assured and are subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions.

    In addition to the Department of Energy loan funding, we have issued $1.4 billion of first mortgage bonds to finance a substantial portion of the Vogtle expansion that will not be funded by the


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    Department of Energy. As of September 30, 2017, we had $3.1 billion of long-term funding in place for the $3.9 billion invested in the Vogtle project to-date. We anticipate utilizing capital markets financing for any Vogtle related costs that we are not able to advance under the Department of Energy-guaranteed loans.

    Bond Financings

    On October 12, 2017, we closed on a $122.6 million direct bank purchase of tax-exempt bonds and used the proceeds to retire commercial paper that was issued in January 2017 in connection with the redemption of our remaining auction rate securities. See Note K of Notes to Unaudited Consolidated Financial Statements for more information regarding this refinancing.

    In late 2017 or early 2018, we plan to issue approximately $400 million of tax-exempt pollution control revenue bonds, the proceeds of which will be used to refinance $400 million of existing pollution control bonds that are callable on January 1, 2018 and that have higher interest rates than our other tax-exempt debt. When issued, out payment obligations related to these bonds will be secured ratably with all other debt under our first mortgage indenture.

    As of September 30, 2017, we had $980.8 million of outstanding obligations related to tax-exempt private activity bonds related to certain of our pollution control facilities. The Tax Cut and Jobs Act, as proposed by members of the House of Representatives on November 2, 2017, could take away our ability to utilize tax-exempt private activity bonds to finance or refinance qualifying pollution control facilities if issued on or after January 1, 2018 and impact the interest rates on our private activity bonds outstanding prior to January 1, 2018.

    Statements. For more detailed information regarding our financing plans, see "Item 7—MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Financing Activities" in our 20162019 Form 10-K.

    Credit Rating Risk

    The table below sets forth our current ratings from S&P Global Ratings, Moody's Investors Service and Fitch Ratings.

    ​ ​​ ​​ ​​

    Our Ratings

    S&P

    Moody's

    Fitch

    ​​​ ​​ ​​

    Long-term ratings:

    Senior secured rating

    		A-Baa1A-

    Issuer/unsecured rating(1)

    		A-Baa2N/R(2)

    Rating outlook

    		NegativeNegativeRating Watch Negative

    Short-term rating:

    Commercial paper rating

    		A-2P-2F2
    ​​​ ​​​​
    (1)
    We currently have no long-term debt that is unsecured.

    (2)
    N/R indicates no rating assigned for this category.

    We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable collateral. Our primary exposure to potential collateral postings is at rating levels of BBB–/Baa3 or below. As of September 30, 2017, our maximum potential collateral requirements were as follows:

    At senior secured rating levels:


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    At senior unsecured or issuer rating levels:

    The Rural Utilities Service Loan Contract contains covenants that, upon a credit rating downgrade below investment grade by two rating agencies, could result in restrictions on issuing debt. Certain of our pollution control bond agreements contain provisions based on the ratings assigned to the bonds (which could be related to either our rating or a bond insurer's rating if the bonds are insured) that, upon a credit rating downgrade below specified levels, could result in increased interest rates. Also, borrowing rates and commitment fees in two of our line of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades.

    Given our current level of ratings, our management does not have any reason to expect a downgrade that would result in any material impacts to our business. However, our ratings reflect only the views of the rating agencies and we cannot give any assurance that our ratings will be maintained at current levels for any period of time.

    Newly Adopted or Issued Accounting Standards

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

    Item 3.    Quantitative and Qualitative Disclosures About Market Risk

    There have not been any material changes to market risks from those reported in "Item 7A—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK" ofin our 20162019 Form 10-K.


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    Item 4.    Controls and Procedures

    As of SeptemberJune 30, 2017,2020, 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 SeptemberJune 30, 20172020 that have materially affected, or are reasonably likely to affect, our internal control over financial reporting.


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    PART II—OTHER INFORMATION

    Item

    -tem 1.    Legal Proceedings

    Except as disclosed under "Item 1—Legal Proceedings" in our quarterly report on Form 10-Q for the quarterly period ended June 30, 2017, there

    There have been no material changes fromto the legal proceedings disclosed in "Item 3—LEGAL PROCEEDINGS" in our 20162019 Form 10-K.

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

    Item 1A.    Risk Factors

    Except as discussed below, there have been no material changes from

    We and our members are subject to risks related to the risk factors disclosed in "Item 1A—RISK FACTORS" in our 2016 Form 10-K.

    Our participation inCOVID-19 pandemic, including, but not limited to, disruption to the development and construction of Vogtle Units No. 3 and No. 4 could have4.

    The World Health Organization has declared a material impact on our financial conditionpandemic 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 results of operations.

    We are contractually committed to participating in the construction of two additional nuclear units at Plant Vogtle and have committed significant capital expenditures to this endeavor. The construction of large, complex generating plants involves significant financial risk. Further, no nuclear plants have been constructedGeorgia. In response, most jurisdictions, including in the United States, using advanced designs, such as the Westinghouse AP1000 design,have instituted restrictions on travel, public gatherings, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also rely onnon-essential business operations. While some jurisdictions, including Georgia, Power and Southern Nuclear as our agents for the oversighthave relaxed these restrictions, many of the constructionrestrictions remain in place and there is no guarantee that restrictions will not be reimposed. These restrictions have significantly disrupted economic activity across the United States, including Georgia, and have caused volatility in capital markets at certain periods during 2020. The effects of the continued COVID-19 pandemic and related responses could include additional unitsdisruptions 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 Plant Vogtlefair value, and do not exercise direct control overimpairment 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 and many of our members have temporarily suspended late fees and service disconnections for certain periods in response to the pandemic.

    Additionally, the effects of the COVID-19 pandemic could further disrupt or delay construction, process.

    Our current project budget for thetesting, supervisory, and support activities at Vogtle Units which includes capital costs, allowance for funds used during construction and a contingency amount, is $7.0 billion and the scheduled commercial operation dates are November 2021 for Unit No. 3 and November 2022 for Unit No. 4. Certain eventsIn 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 materially delayed the original commercial operation datestested 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 increased the original project budget. The most significant of these relate to the EPC Contractor's filing for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code and its subsequent rejection of the fixed price EPC Agreement.

    We continue to be subject to construction risks and no longer have the benefit of the "fixed" price EPC Agreement, which means that any cost overruns will be allocated to the Co-owners based on their ownership interest percentage. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:


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    Additionally, we do not control the determination as to whether the Vogtle project continues to move forward as continued construction ofworkforce at Vogtle Units No. 3 and No. 4, is subjectwhich totaled approximately 20% of the then-existing workforce. This reduction in workforce was a mitigation action intended to approvaladdress ongoing challenges with labor productivity that were exacerbated by the Georgia Public Service Commission. On August 31, 2017, Georgia Power recommended that constructionimpact of the COVID-19 pandemic on the Vogtle Units No. 3 and No. 4 be continued with Southern Nuclear serving as project manager in its VCM 17 Report filedworkforce 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 Georgia Public Service Commission.recommendations from the Centers for Disease Control and Prevention. The recommendationApril 2020 reduction did reduce absenteeism, providing an improvement in operational efficiency and allowing for increased social distancing. From the initial peak in April 2020, the number of active cases at the site declined significantly during May and early June, but began increasing again in mid-June and continues to continueimpact productivity levels and pace of activity completion. As a result of these factors, overall production improvements have not been achieved at the level anticipated, contributing 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 supported by all the Co-ownerscurrently

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    estimated to be between $150 and $250 million (of which our 30% interest is $45 to $75 million) and is basedincluded 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 results of a comprehensiveconstruction schedule cost-to-complete and cancellation assessment. The Georgia Public Service Commission is expected to make a decision on these matters by February 6, 2018.

    Further, on November 2, 2017, the Co-owners amended the Joint Ownership Agreements to provide that holders of at least 90% of the ownership interests inbudget for Vogtle Units No. 3 and No. 4 must vote to continue construction upon the occurrence of any of those adverse events. As we are a 30% owner in the Vogtle project, we, along with Georgia Power and the Municipal Electricity Authority of Georgia, will need to each determine to move forward with the Vogtle project upon the occurrence of certain adverse events. In the event the Vogtle project is cancelled, our proportionate share of the Co-owners' cancellation costs are estimated to be approximately $230 million. As of September 30, 2017, our total investment in the additional Vogtle units was approximately $3.9 billion. If the project is cancelled, we would seek regulatory accounting treatment to amortize our investment in the Vogtle project over a long-term period which would require the approval of our board of directors, and we would submit the regulatory accounting treatment request to the Rural Utilities Service for its approval.

    Following the bankruptcy of the EPC Contractor, the rejection of the EPC Agreement and our comprehensive cost-to-complete assessment, we increased our project budget to $7.0 billion from $5.0 billion. This increase is expected to increase our capital expenditures through 2022 and lead to a corresponding increase in our long-term debt outstanding at completion of the Vogtle units to $11.5 billion from the previously disclosed amount of $10 billion. These increases in capital expenditures and in our long-term debt will continue to constrain our equity ratio and will affect certain of our other financial metrics. Increased debt and the related impacts on our financial metrics could negatively impact our credit ratings. Any downgrade in our credit ratings would increase our borrowing costs and decrease our access to the credit and capital markets.

    The long-term project cost will also be impacted by our ability to finance the capital costs at competitive interest rates. We are currently unable to make advances from the remaining $1.4 billion of committed funds under our Loan Guarantee Agreement with the Department of Energy and will not be able to make additional advances until we enter into an amendment to the Loan Guarantee Agreement with the Department of Energy. The timing of further advances under the Loan Guarantee Agreement is uncertain but is likely to occur in 2018. Prolonged inability to access funding pursuant to the Department of Energy Loan Guarantee Agreement may constrain our liquidity and lead us to finance certain expenditures through alternative resources, likely at a higher interest rate. We have received a conditional commitment from the Department of Energy for approximately $1.6 billion of additional loan guarantees; however final approval of these additional amounts cannot be assured. See Note K of Notes to Unaudited Consolidated Financial Statements for additional information about the Loan Guarantee Agreement and related conditions.

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


    Table The ultimate impact of Contents

    Any inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the cost to the Co-owners of Vogtle Units No. 3 and No. 4, and therefore on our financial condition and results of operations.

    On June 9, 2017, Georgia PowerCOVID-19 pandemic and the other Co-ownersresulting economic contraction on us and Toshiba entered into the Guarantee Settlement Agreement. Pursuant to the Guarantee Settlement Agreement, Toshiba acknowledged the $3.68 billion amount of its Guarantee Obligations, of which our proportionate share is approximately $1.1 billion, and that the Guarantee Obligations exist regardless of whether Vogtle Units No. 3 and No. 4 are completed. The Guarantee Settlement Agreement also provides for a schedule of payments for the Guarantee Obligations that began in October 2017 and continues through January 2021. In the event Toshiba receives certain payments, including sale proceeds, from or related to Westinghouse (or its subsidiaries) or Toshiba Nuclear Energy Holdings (UK) Limited (or its subsidiaries), itmembers will hold a portion of such payments in trust for the Co-owners and promptly pay them over as offsets against any remaining Guarantee Obligations. Under the Guarantee Settlement Agreement, the Co-owners will forbear from exercising remedies in respectdepend of the Toshiba Guarantee, including drawing on the Westinghouse Lettersseverity and duration of Credit, until June 30, 2020, unless certain events of nonpayment, insolvency, or other material breach of the Guarantee Settlement Agreement by Toshiba occur. If such an event occurs, the balance of the Guarantee Obligations will become immediately dueeach and payable, and the Co-owners may exercise any and all rights and remedies, including drawing on the Westinghouse Letters of Credit without restriction. In addition, the Guarantee Settlement Agreement does not restrict the Co-owners from fully drawing on the Westinghouse Letters of Credit in the event they are not renewed or replaced prior to the expiration date.

    On November 9, 2017, Toshiba released its financial results for the second quarter of fiscal year 2017, which reflected a negative shareholders' equity balance of approximately $5.5 billion as of September 30, 2017. Toshiba also announced the existence of material events and conditions that raise substantial doubt about Toshiba's ability to continue as a going concern. As a result, substantial risk regarding the Co-owners' ability to fully collect the Guarantee Obligations continues to exist. An inability or other failure by Toshiba to perform its obligations under the Guarantee Settlement Agreement could have a further material impact on the net cost to the Co-owners of Vogtle Units No. 3 and No. 4, and, therefore, on our financial condition and results of operations as well.

    In October and November 2017, Georgia Power, on behalf of the Co-owners, received the first two installments of the Guarantee Obligations totaling $377.5 million from Toshiba, of which our proportionate share was $113.3 million. We are considering potential options with respect to our right to payments under the Guarantee Settlement Agreement and our claims against the EPC Contractor in the EPC Contractor's bankruptcy proceeding, including a potential sale of those payment rights and bankruptcy claims. Any such transaction cannot be assured and would be subject to Department of Energy consents and related approvals under the Loan Guarantee Agreement and related agreements.

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

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

    Not Applicable.

    Item 3.    Defaults upon Senior Securities

    Not Applicable.

    Item 4.    Mine Safety Disclosures

    Not Applicable.

    Item 5.    Other Information

    Not Applicable.


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    Item 6.    Exhibits

    NumberDescription
    4.1Seventy-Fourth Supplemental Indenture, dated as of October 1, 2017, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2017A (Burke) Note, the Series 2017B (Burke) Note, the Series 2017A (Heard) Note and the Series 2017A (Monroe) Note.

    Number
    4.2

    Seventy-Fifth Supplemental Indenture, dated as of October 18, 2017, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Amendment of the Original Indenture.Description

    31.1 
    4.3

    Amendment, dated October 18, 2017, to Ninth Amended and Restated Loan Contract, dated as of September 2, 2014, between Oglethorpe and the United States of America.


    10.1

    Agreement regarding Additional Participating Party Rights and Amendment No. 3 to Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement and Amendment No. 4 to Plant Vogtle Owners Agreement Authorizing Development, Construction, Licensing and Operation of Additional Generating Units, dated as of November 2, 2017, by and among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia, MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, MEAG Power SPVP, LLC, and the City of Dalton.


    31.1


    31.2 
    31.2


    32.1 
    32.1


    32.2 
    32.2


    101 
    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 13, 2017

    By:

    Date:August 12, 2020By:/s/ Michael L. Smith
    		Michael L. Smith

    President and Chief Executive Officer

    Date: November 13, 2017



    Date:August 12, 2020/s/ Elizabeth B. Higgins
    		Elizabeth B. Higgins

    Executive Vice President and

    Chief Financial Officer

    (Principal Financial Officer)



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