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PART IV

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

FORM 10-K

(An Electric Membership Corporation)
(Exact name of registrant as specified in its charter)

        Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No ý

        Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes ý Noo

        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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

        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):

        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 oNoý

        State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter.The Registrant is a membership corporation and has no authorized or outstanding equity securities.

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

        Documents Incorporated by Reference:None

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OGLETHORPE POWER CORPORATION

20172018 FORM 10-K ANNUAL REPORT

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CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTSINFORMATION

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

    Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and there are important factors that could cause actual results to differ materially from those expressed or implied by these forward-looking statements. Some of the risks, uncertainties and assumptions that may cause actual results to differ from these forward-looking statements are described under the heading "RISK FACTORS" and in other sections of this annual report. In light of these risks, uncertainties and assumptions, the forward-looking events and circumstances discussed in this annual report may not occur.

    Any forward-looking statement speaks only as of the date of this annual 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:

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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;



•

decisions madea decision by Georgia Power Company to cancel the Georgia Public Service Commission in the regulatory process related to the two additional Vogtle units at Plant Vogtle;



•

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



•

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



•

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



•

our ability to receive advances under the U.S. Department of Energy loan guarantee agreement for 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-year period and the Department of Energy's decision to require such repayment;



•

the continued availability of funding from the Rural Utilities Service;



•

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;



•

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



•

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

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upon budgeted expenditures and are generally recognized and billed to our fixed costs, which do not vary significantly from month to month; therefore, capacity charges are billed and capacity revenues are recognizedmembers in substantially equal monthly amounts.installments over the course of the year. We may recognize capacity revenues that exceed our actual fixed costs and targeted margins in any given interim reporting period. At each interim reporting period, we assess our projected revenue requirements through year end and if required, we reduce our capacity revenues and recognize a refund liability to our members. See Note 1e for information regarding revenue recognition.

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OUR POWER SUPPLY RESOURCES

General

    We supply capacity and energy to our members for a portion of their requirements from a combination of our fleet of generating assets and power purchased from other suppliers. In 2017,2018, we supplied approximately 63%57% of the retail energy requirements of our members.

Generating Plants

    Our fleet of generating units total 7,8437,791 megawatts of summer planning reserve capacity, including 728731 megawatts of Smarr EMC assets, which we manage. ThisOur generation portfolio includes our interests in units fueled by nuclear, coal, natural gas, oil and water.hydro units. Georgia Power, the Municipal Electric Authority of Georgia (MEAG) and the City of Dalton also have interests in nine of these units at Plants Hatch, Vogtle, Wansley and Scherer. Georgia Power serves as operating agent for these nine units. Georgia Power also has an interest in the three units at Rocky Mountain, which we operate. In addition to our 31 generating units, we operate and manage six gas-fired generating units on behalf of Smarr EMC.

    See "PROPERTIES" for a description of our generating facilities, fuel supply and the co-ownership arrangements. For a description of Smarr EMC's assets, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member Power Supply Resources –Smarr EMC."

Power Purchase and Sale Arrangements

    We currently have no material power purchase or sale agreements.

    We purchase small amounts of energy from a "qualifying facility" under the Public Utility Regulatory Policies Act of 1978.1978 under a contract that will terminate on March 31, 2019. Under a waiver order from the Federal Energy Regulatory Commission, we historically made all purchases the members would have otherwise been required to make under the Public Utility Regulatory Policies Act and we were relieved of our obligation to sell certain services to "qualifying facilities" so long as the members make those sales. In 2017,2018, our purchases from this qualifying facility provided less than 0.1% of the energy we supplied to our members. Under their wholesale power contracts, the members may now make such purchases instead of us.

    We manage Green Power EMC's purchase of energy from 119120 megawatts of renewable resources. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources –Green Power EMC."

    We have interchange, transmission and/or short-term capacity and energy purchase or sale agreements with a number of power marketers and other power suppliers. The agreements provide variously for the purchase and/or sale of capacity and energy and/or for the purchase of transmission service.

Future Power Resources

Plant Vogtle Units No. 3 and No. 4

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

    In 2008, Georgia Power, acting for itself and as agent for the Co-owners, entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement) with Westinghouse Electric Company LLC and Stone & Webster, Inc., which was subsequently acquired by Westinghouse and changed its name to WECTEC Global Project Services Inc. (collectively, Westinghouse). Pursuant to the EPC Agreement, Westinghouse agreed to design, engineer, procure, construct and test two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology and related facilities at Plant Vogtle. Under the terms of the EPC Agreement, the Co-owners agreed to pay a purchase price subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain payment obligations of Westinghouse under the EPC Agreement (the Toshiba Guarantee),

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including any liability of Westinghouse for abandonment of work.    Until March 2017, construction on Units No. 3 and No. 4 continued under the substantially fixed price EPC Agreement.

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    OnAgreement. In March 29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the bankruptcy filing, Georgia Power, acting for itself and as agent for the other Co-owners, entered into an Interim Assessment Agreement with Westinghouse and WECTEC Staffing Services LLC to provide for a continuation of work at Vogtle Units No. 3 and No. 4. The Interim Assessment Agreement expired onEffective in July 27, 2017, upon the effective date of the Services Agreement discussed below.

    Subsequent to Westinghouse's bankruptcy filing, a number of subcontractors to Westinghouse alleged non-payment by Westinghouse for amounts owed for work performed on Vogtle Units No. 3 and No. 4. Georgia Power, acting for itself and as agent for the Co-owners, has taken actions to remove liens on the site filed by these subcontractors through the posting of surety bonds. Related to such liens, certain subcontractors have filed, and additional subcontractors may file, actions against Westinghouse and the Co-owners to preserve their payment rights with respect to such claims. All amounts associated with the removal of subcontractor liens and payment of other Westinghouse pre-petition accounts payable have been paid or accrued as of December 31, 2017.

    On June 9, 2017, Georgia Power and 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 was $3.68 billion (the Guarantee Obligations), of which our proportionate share was $1.1 billion. The Guarantee Settlement Agreement provided for a schedule of payments for the Guarantee Obligations beginning in October 2017 and continuing through January 2021. Toshiba made the first three payments as scheduled. On December 8, 2017, the Co-owners, certain affiliates of the Municipal Electric Authority of Georgia, and Toshiba entered into Amendment No. 1 to the Guarantee Settlement Agreement (the Settlement Agreement Amendment). The Settlement Agreement Amendment provided that Toshiba's remaining scheduled payment obligations under the Guarantee Settlement Agreement were due and payable in full on December 15, 2017, which Toshiba satisfied on December 14, 2017. Pursuant to the Settlement Agreement Amendment, Toshiba was deemed to be the owner of certain pre-petition bankruptcy claims of the Co-owners and certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of Westinghouse's potential obligations under the EPC Agreement.

    Additionally, on June 9, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, and Westinghouse entered into a services agreement which was amended and restated on July 20, 2017 (the Services Agreement), forpursuant to which Westinghouse to transition construction management of Vogtle Units No. 3is providing facility design and No. 4 to Southern Nuclearengineering services, procurement and to provide ongoing design, engineering,technical support and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved Westinghouse's motion seeking authorization to (i) enter into the Services Agreement, (ii) assumestaff augmentation on a time 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.materials cost basis. The Services Agreement and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreementprovides that it will continue until the start-up and testing of Vogtle Units No. 3 and No. 4 is complete and electricity is generated and sold from both units. The Services Agreement is terminable by the Co-owners upon 30 days' written notice.

    EffectiveIn October 23, 2017, Georgia Power, acting for itself and as agent for the other Co-owners, entered into a construction completion agreement with Bechtel Power Corporation, wherebypursuant to which Bechtel will serveserves as the primary contractor for the remaining construction activities for Vogtle Units No. 3 and No. 4 (the Bechtel Agreement). 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 beis reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, and not jointly, liable for its proportionate share, based on its ownership interest,

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of all amounts owed to Bechtel under the Bechtel Agreement. The Co-owners may terminate the Bechtel Agreement at any time for their convenience, provided that the Co-owners will be required to pay amounts related to work performed prior to the termination (including the applicable portion of the base fee), certain termination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may terminate the Bechtel Agreement under certain circumstances, including certain Co-owner suspensions of work, certain breaches of the Bechtel Agreement by the Co-owners, Co-owner insolvency and certain other events. Pursuant to the loan guarantee agreement between us and the Department of Energy, we are required to obtain the Department of Energy's approval of the Bechtel Agreement prior to obtaining any further advances under the loan guarantee agreement.

    OnIn 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. PursuantThese joint ownership agreements, including the Co-owner approval requirements, were subsequently amended, effective August 31, 2018. As described below, certain provisions of the Joint Ownership Agreements were modified further on September 26, 2018 by the Term Sheet that was memorialized on February 18, 2019 when the Co-owners entered into certain amendments (the Global Amendments) 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; (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 Georgia Power's seventeenth Vogtle construction monitoring (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(as amended, 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.Agreements).

    On December 21, 2017, the Georgia Public Service Commission took a series of actions related to the construction of Vogtle Units No. 3 and No. 4 and issued its related order on January 11, 2018. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation thatto continue construction of Vogtle Units No. 3 and No. 4, be completed, with Southern Nuclear Operating Company, Inc. serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain conditions change and assumptions upon which Georgia Power's seventeenth VCMVogtle construction monitoring (VCM) report are based do not materialize, both Georgia Power and the Public Service Commission reservereserved the right to reconsider the decision to continue construction. PartiesThird parties have filed two petitions with the Fulton County Superior Court appealing the Georgia Public Service Commission's January 11, 2018 order. On December 21, 2018, the Superior Court granted Georgia Power's motion to dismiss the two appeals. On January 9, 2019, those parties appealed that decision to the Georgia Court of Appeals. Georgia Power has stated that it believes these appeals havethe appeal has no merit; however, an adverse outcome in one or both of these appealsthe appeal combined with subsequent adverse action by the Public Service Commission could have a material impact on our financial condition and results of operations.

    We expectIn 2018, Georgia Power advised us that it became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts included in its seventeenth VCM report. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast the cost to complete the project and engaged a third party to independently assess this analysis, forecast, and existing project controls for identifying budget variances. Following this analysis, Georgia Power proposed an increased construction budget and included a revised estimate to complete in its nineteenth VCM report filed with the Georgia Public Service Commission in August 2018. This revised estimate

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included an approximate $1.5 billion increase in capital costs (our 30% share is approximately $450 million) and a project-level contingency in an amount of $800 million (our 30% share is $240 million). The increase in the revised budget is primarily attributable to Bechtel and subcontractor construction costs, including craft labor incentives, as well as expenses for project management, oversight and support. The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, did not change in connection with these budget revisions.

    Further, Georgia Power informed the Public Service Commission in its nineteenth VCM report that it did not intend to be placed in service by November 2021 and November 2022, respectively. Our project budgetseek rate recovery for its proportionate share of the additional capital costs identified in that report. As a result of Georgia Power's decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle units is $7.0Units No. 3 and No. 4 were required to vote to continue construction.

    In September 2018, the Co-owners voted to continue construction of Vogtle Units No. 3 and No. 4. In connection with our vote to continue construction, we approved a revised budget of $7.5 billion whichfor our 30% ownership interest. The impact of the additional project costs on our budget was substantially mitigated by nearly $500 million of contingency included in our prior budget. As with our prior budgets and consistent with our conservative budget practices, our revised budget includes a separate Oglethorpe-level contingency amount in addition to capital costs, allowance for funds used during construction, and a contingency amount. This budget is netour allocation of the $1.1 billionproject-level contingency. We and some of payments we received from Toshiba underour members have implemented various rate management programs to lessen the Guarantee Settlement Agreement.impact on rates when Vogtle Units No. 3 and No. 4 reach commercial operation. As of December 31, 2017,2018, our total investment in the additional Vogtle units was approximately $2.9 billion, net of the payments received from Toshiba under the Guarantee Settlement Agreement. The payments from Toshiba were recorded as a reduction to the construction work in progress balance for the additional Vogtle units.

    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 the Rural Utilities Service.

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    We have a $3.1 billion federal loan guarantee from the Department of Energy, under which we have advanced $1.7 billion as of December 31, 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 to incorporate provisions relating to the Bechtel Agreement and other replacement agreements. While not assured, we expect to satisfy these conditions in the second quarter of 2018.

    On September 28, 2017, the Department of Energy issued a conditional commitment to us for up to $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of certain 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 7 of Notes to Consolidated Financial Statements. We have also financed an additional $1.4 billion of the capital costs of the Vogtle units through capital market debt issuances. For additional information regarding the financing of Vogtle Units No.3 and No.4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Financial Condition – Financing Activities – Department of Energy-Guaranteed Loan" and "Capital Requirements – Capital Expenditures."

    Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related to Vogtle Units No. 3 and No. 4. We expect to receive these tax credits in accordance with our 30% ownership interest in the Vogtle Units and are analyzing various options to monetize these credits with a third party. We estimate that the nominal value of our allocation of production tax credits will be approximately $660 million and will be earned for eight years post commercial operation.$3.9 billion.

    As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors,vendors; labor productivity, and availability, and/or cost escalation; procurement, fabrication, delivery, assembly and/or installation and installationtesting, including any required engineering changes, of plant systems, structures and components,components; or other issues could further impact the projected schedule and cost. AspectsMonthly construction production targets required to maintain the current project schedule will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and additional craft laborers must be retained and deployed.

    Georgia Power and Southern Nuclear are in the process of validating recent construction progress in comparison to the Westinghouse AP1000 design are based on new technologiesprojected schedule and commercial operationverifying and updating quantities of commodities remaining to install, labor productivity, and forecasted staffing needs. This verification process, led by Southern Nuclear, is expected to be completed during the second quarter of 2019. Although the verification is not complete, we currently do not anticipate any material changes to our project budget of $7.5 billion or the Public Service Commission approved in-service dates of November 2021 and November 2022 as a result of this designverification process. However, the current schedule being utilized to manage construction at the Vogtle site, which targets in-service dates in advance of November 2021 and November 2022, may be adjusted to reflect updated information provided by the verification process. The ultimate impact on cost and schedule, if any, will not be known until the verification process is completed. Georgia Power has yetstated that it is required to be tested.report the results and any project impacts to the Public Service Commission by May 15, 2019.

    There have been technical and procedural challenges to the construction and licensing of Vogtle Units No. 3 and No. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

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    In late 2018, the first four nuclear units to utilize Westinghouse's AP1000 technology began commercial operation in China. Recently, one of these units reportedly experienced a failure of one of its four reactor coolant pumps and is not operating pending determination of the cause of the failure and replacement of the pump. The other three nuclear units remain in operation.

    In connection with the September 2018 vote to continue construction, Georgia Power entered into a binding term sheet with the other Co-owners and MEAG's wholly-owned subsidiaries MEAG Power SPVJ, LLC, MEAG Power SPVM, LLC, and MEAG Power SPVP, LLC that mitigated certain financial exposure for the other Co-owners and offered to purchase production tax credits from each of the other Co-Owners, at that Co-owner's option (the Term Sheet). On February 18, 2019, the Co-owners entered into the Global Amendments to memorialize the provisions of the Term Sheet. Pursuant to the Global Amendments and consistent with the Term Sheet, the Joint Ownership Agreements provide that:

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each Co-owner is obligated to pay its proportionate share of construction costs for Vogtle Units No. 3 and No. 4 based on its ownership interest up to (i) the estimated cost at completion ("EAC") for Vogtle Units No. 3 and No. 4 which formed the basis of Georgia Power's forecast of $8.4 billion in Georgia Power's nineteenth VCM report filed with the Georgia Public Service Commission plus (ii) $800 million of additional construction costs;



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Georgia Power will be responsible for 55.7% of construction costs, subject to exceptions, that exceed the EAC in the nineteenth VCM report by $800 million to $1.6 billion (resulting in up to $80 million of potential additional costs to Georgia Power which would save Oglethorpe up to $44 million), with the remaining Co-owners responsible for 44.3% of such costs pro rata in accordance with their respective ownership interests (equal to 24.5% for our 30% ownership interest); and



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Georgia Power will be responsible for 65.7% of construction costs, subject to exceptions, that exceed the EAC in the nineteenth VCM report by $1.6 billion to $2.1 billion (resulting in up to a further $100 million of potential additional costs to Georgia Power which would save Oglethorpe up to an additional $55 million), with the remaining Co-owners responsible for 34.3% of such costs pro rata in accordance with their respective ownership interests (equal to 19.0% for our 30% ownership interest).

    If the EAC is revised and exceeds the EAC in the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, other than Georgia Power, will have a one-time option at the time the project budget forecast is so revised to tender a portion of its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Co-owner's remaining share of construction costs in excess of the EAC in the nineteenth VCM report plus $2.1 billion. In this event, Georgia Power would have the option of cancelling the project in lieu of purchasing a portion of the ownership interest of any other Co-owner. If Georgia Power accepts the offer to purchase a portion of another Co-owner's ownership interest in Vogtle Units No. 3 and No. 4, the ownership interest to be conveyed from the tendering Co-owner to Georgia Power will be calculated based on the proportion of the cumulative amount of construction costs paid by each such tendering Co-owner and by Georgia Power as of the commercial operation date of Vogtle Unit No. 4. For purposes of this calculation, payments made by Georgia Power on behalf of another Co-owner in accordance with the second and third bullets above will be treated as payments made by the applicable Co-owner. This option to tender a portion of our interest to Georgia Power upon such a budget increase would allow us to freeze our construction budget associated with the Vogtle project in exchange for a portion of our 30% ownership interest.

    In the event the actual costs of construction at completion of a unit are less than the EAC reflected in the nineteenth VCM report and (i) Vogtle Unit No. 3 is placed in service by the currently scheduled date of November 2021 or (ii) Vogtle Unit No. 4 is placed in service by the currently scheduled date of November 2022, Georgia Power will be entitled to 60.7% of the cost savings with respect to the relevant unit and the remaining Co-owners will be entitled to 39.3% of such savings on a pro rata basis in accordance with their respective ownership interests.

    Pursuant to the Global Amendments, the Co-owners will continue to retain a third party to independently consult, advise and report to the Co-owners on issues pertaining to (i) project management and controls,

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(ii) organizational controls, (iii) commercial management plans and (iv) interim project reports until released by 67% of the Co-owners.

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

    The Global Amendments provide that Georgia Power may cancel the project at any time at its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amounts outstanding under our loan guarantee agreement with the Department of Energy over a five-year period as discussed in Note 7 of Notes to Consolidated Financial Statements.

    In March 2019, we entered into an amended and restated loan guarantee agreement with the Department of Energy to increase our existing loan guarantee agreement from $3.1 billion to nearly $4.7 billion and amend other terms of the agreement. As of March 15, 2019, we have borrowed $2.4 billion under the loan guarantee agreement. For additional information regarding terms of the loan guarantee agreement with the Department of Energy, including conditions for future advances, potential repayment over a five-year period, covenants and events of default, see Note 7a of Notes to Consolidated Financial Statements.

    We have also financed $1.9 billion of the capital costs of the Vogtle units through capital market debt issuances. We anticipate financing any project costs not guaranteed by the Department of Energy in the capital markets. For additional information regarding the financing of Vogtle Units No. 3 and No. 4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition –Financing Activities – Department of Energy-Guaranteed Loans."

    Under the Bipartisan Budget Act of 2018, we qualify for nuclear production tax credits related to Vogtle Units No. 3 and No. 4. We expect to receive these tax credits in accordance with our 30% ownership interest in the Vogtle Units. We estimate that the nominal value of our allocation of production tax credits will be approximately $700 million and will be earned for eight years post commercial operation. Pursuant to the Global Amendments, Georgia Power agreed to purchase our allocation of production tax credits at varying purchase prices dependent upon the actual cost to complete construction of Vogtle Units No. 3 and No. 4 as compared to the EAC included in the nineteenth VCM report. Any purchases will be at our option. The purchases would occur during the month after such production tax credits are earned and would be at the following purchase prices: (i) 88% of face value if the actual cost remains at or below the EAC reflected in the nineteenth VCM report; (ii) 91% of face value if the actual cost increases by no more than $299 million over

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the EAC reflected in the nineteenth VCM report; (iii) 95% of face value if the actual cost increases $300 million but less than $600 million over the EAC reflected in the nineteenth VCM report; and (iv) 98% of face value if the actual cost increases by $600 million or more over the EAC reflected in the nineteenth VCM report. We will continue to analyze various options to monetize these credits with one or more third parties, including Georgia Power. In order to maximize the value of these production tax credits, we do not anticipate entering into any agreement to sell these production tax credits until one or both of the Vogtle Units reach commercial operation. We expect to use the proceeds received from the sale of production tax credits to offset operating costs following commercial operation of the Vogtle Units. Any amounts received from these sales will not affect our project budget.

    MEAG is currently involved in litigation with JEA regarding a power purchase agreement for approximately 9% of the total output of Vogtle Units No. 3 and No. 4 for the first 20 years of operation. This litigation could impact MEAG's ability to finance the MEAG Power SPVJ portion of its interest in Vogtle Units No. 3 and No. 4; however, there are provisions in the Joint Ownership Agreements that permit the other Co-owners to fund construction in the event that one Co-owner fails to fund its proportionate costs. MEAG and Georgia Power have entered into a financing agreement for Georgia Power to provide MEAG up to an additional $300 million of financing. JEA has publicly stated that it intends to honor its obligations under the power purchase agreement unless relieved of its obligations by a court. MEAG has stated that it believes JEA's claims are without merit and that it will prevail in these proceedings.

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

    See "RISK FACTORS" for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

Other Future Power Resources

    From time to time, we may assist our members in investigating potential new power supply resources, after compliance with the terms of the New Business Model Member Agreement. See "OGLETHORPE POWER CORPORATION – New Business Model Member Agreement."

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OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES

Member Demand and Energy Requirements

    Our members are listed below and include 38 of the 41 electric distribution cooperatives in the State of Georgia.

    Our members serve approximately 1.9 million electric consumers (meters) representing approximately 4.1 million people. Our members serve a region covering approximately 38,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 151 of the State's 159 counties. Historically, our members' sales by customer class have been approximately two-thirds to residential consumers and slightly less than one-third to commercial and industrial consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. Each year we file an exhibit containing financial and statistical information for our 38 members for the most recent three year period with one of our quarterly reports on Form 10-Q.

    The following table shows the aggregate peak demand and energy requirements of our members for the years 20152016 through 2017,2018, and also shows the amount of their energy requirements that we supplied. From 20152016 through 2017,2018, peak demand of the members and their energy requirements have fluctuated based on various factors, including milder weather in 2015 and 2017. In 2016, the amount of energy we supplied to the members increased nearly 40%, primarily as a result of the use of Smith Energy Facility to meet the members' energy requirements, as well as an increase in total member requirements.

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Service Area and Competition

    The Georgia Territorial Act regulates the service rights of all retail electric suppliers in the State of Georgia. Pursuant to the Georgia Territorial Act, the Georgia Public Service Commission assigned substantially all areas in the State to specified retail suppliers. With limited exceptions, our members have the exclusive right to provide retail electric service in their respective territories, which are predominately outside of the municipal limits existing at the time the Georgia Territorial Act was enacted in 1973. The principal exception to this rule of exclusivity is that electric suppliers may compete for most new retail loads of 900 kilowatts or greater. Parties have unsuccessfully sought and will likely continue to seek to advance legislative proposals that will directly or indirectly affect the Georgia Territorial Act in order to allow increased retail competition in our members' service territories.

    The Georgia Public Service Commission may reassign territory only if it determines that an electric supplier has breached the tenets of public convenience and necessity. The Georgia Public Service Commission may transfer service for specific premises only if: (i) it determines, after joint application of electric suppliers and proper notice and hearing, that the public convenience and necessity require a transfer of service from one electric supplier to another; or (ii) it finds, after proper notice and hearing, that an electric supplier's service to the premises is not adequate or dependable or that its rates, charges, service rules and regulations unreasonably discriminate in favor of or against the consumer utilizing the premises and the electric utility is unwilling or unable to comply with an order from the Georgia Public Service Commission regarding the service.

    Since 1973, theThe Georgia Territorial Act has allowedallows limited competition among electric utilities in Georgia by allowing the owner of any new facility located outside of municipal limits and having a connected load upon initial full operation of 900 kilowatts or greater to receive electric service from the retail supplier of its choice. Our members, with our support, are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. The number of commercial and industrial loads served by our members continues to increase annually. While the competition for 900-kilowatt loads represents onlyThis limited competition in Georgia, this competition has given our members and us the opportunity to develop resources and strategies to operate in an increasingly competitive market.

    For further information regarding members' competitive activities, see "OGLETHORPE POWER CORPORATION –Competition."

Cooperative Structure

    Our members are cooperatives that operate their systems on a not-for-profit basis. Accumulated margins derived after payment of operating expenses and provision for depreciation constitute patronage capital of the consumers of our members. Refunds of accumulated patronage capital to the individual consumers may be made from time to time subject to limitations contained in mortgages between the members and the Rural Utilities Service or loan documents with other lenders. The Rural Utilities Service mortgages generally prohibit these distributions unless (i) after any of these distributions, the member's total equity will equal at least 30% of its total assets or (ii) distributions do not exceed 25% of the margins and patronage capital received by the member in the preceding year and equity is at least 20% of total assets. See "– Members' Relationship with the Rural Utilities Service."

    We are a membership corporation, and our members are not our subsidiaries. Except with respect to the obligations of our members under each member's wholesale power contract with us and our rights under these contracts to receive payment for power and energy supplied, we have no legal interest in (including through a pledge or otherwise), or obligations in respect of, any of the assets, liabilities, equity, revenues or margins of our members. See "OGLETHORPE POWER CORPORATION –Wholesale Power Contracts." The assets and revenues of our members are, however, pledged under their respective mortgages with the Rural Utilities Service or loan documents with other lenders.

    We depend on the revenue we receive from our members pursuant to the wholesale power contracts to cover the costs of operation of our power supply business and satisfy our debt service obligations.

Rate Regulation of Members

    Through provisions in the loan documents securing loans to the members, the Rural Utilities Service exercises control and supervision over the rates for the sale of power of our members that borrow from it. The Rural Utilities Service mortgage indentures of these members require them to design rates with a view to

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maintaining an average times interest earned ratio and an average debt service coverage ratio of not less than

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1.25 and an operating times interest earned ratio and an operating debt service coverage ratio of not less than 1.10, in each case for the two highest out of every three successive years.

    The Georgia Electric Membership Corporation Act, under which each of the members was formed, requires the members to operate on a not-for-profit basis and to set rates at levels that are sufficient to recover their costs and to provide for reasonable reserves. The setting of rates by the members is not subject to approval by any federal or state agency or authority other than the Rural Utilities Service, but the Georgia Territorial Act prohibits the members from unreasonable discrimination in the setting of rates, charges, service rules or regulations and requires the members to obtain Georgia Public Service Commission approval of long-term borrowings.

    Cobb EMC, Diverse Power Incorporated, an EMC, Mitchell EMC, Oconee EMC, Snapping Shoals EMC and Walton EMC have repaid all of their Rural Utilities Service indebtedness and are no longer Rural Utilities Service borrowers. Each of these members now has a rate covenant with its current lender. Other members may also pursue this option. To the extent a member that is not a Rural Utilities Service borrower engages in wholesale sales or sales of transmission service in interstate commerce, it would, in certain circumstances, be subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act.

Members' Relationship with the Rural Utilities Service

    Through provisions in the loan documents securing loans to the members, the Rural Utilities Service also exercises control and supervision over the members that borrow from it in such areas as accounting, other borrowings, construction and acquisition of facilities, and the purchase and sale of power.

    Historically, federal loan programs providing direct and guaranteed loans from the Rural Utilities Service to electric cooperatives have been a major source of funding for the members. Under the current Rural Utilities Service loan programs, electric distribution borrowers are eligible for loans made by the Federal Financing Bank or other lenders and guaranteed by the Rural Utilities Service. Certain borrowers with either low consumer density or higher than average rates and lower than average consumer income are eligible for special loans that bear interest at an annual rate of 5%. However, Rural Utilities Service loan funds are subject to annual federal budget appropriations, and, due to budgetary and political pressures faced by Congress, the availability and magnitude of these loan funds cannot be assured.

    The President's budget for fiscal year 2019,2020, which begins October 2018,2019, proposes a loan program level of $5.5 billion, the same as the current program level. Although Congress has historically rejected proposals to dramatically curtail or redirect the Rural Utilities Service loan program, there can be no assurance that it will continue to do so. Because of these factors,However, we cannot predict the amount or cost of Rural Utilities Service loans that may be available to the members in the future. For additional information regarding the Rural Utilities Service, see "OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders –Rural Utilities Service."

Members' Relationships with Georgia Transmission and Georgia System Operations

    Georgia Transmission provides transmission services to our members for delivery of our members' power purchases from us and other power suppliers. Georgia Transmission and the members have entered into member transmission service agreements under which Georgia Transmission provides transmission service to the members pursuant to a transmission tariff. The member transmission service agreements have a minimum term for network service until December 31, 2060. The members' transmission service agreements include certain elections for load growth above 1995 requirements, with notice to Georgia Transmission, to be served by others. These agreements also provide that if a member elects to purchase a part of its network service elsewhere, it must pay appropriate stranded costs to protect the other members from any rate increase that they would otherwise incur. Under the member transmission service agreements, members have the right to design, construct and own new distribution substations.

    Georgia System Operations has contracts with each of its members, including Georgia Transmission and us, to provide to them the services that it in turn purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. Georgia System Operations also provides operation services for the benefit of our members through agreements with us, including dispatch of our resources

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and other power supply resources owned by the members.

    For information about our relationship with Georgia System Operations, see"OGLETHORPE POWER

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CORPORATION – Relationship with Georgia System Operations Corporation."

Member Power Supply Resources

Oglethorpe Power Corporation

    In 2017,2018, we supplied approximately 63%57% of the retail energy requirements of our members. Pursuant to the wholesale power contracts, we supply each member energy from our generation resources based on its fixed percentage capacity cost responsibility, which are take-or-pay obligations. See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts." Our members satisfy all of their requirements above their purchase obligations to us with purchases from other suppliers as described below.

Contracts with Southeastern Power Administration

    Our members purchase hydroelectric power from the Southeastern Power Administration, or SEPA, under contracts that will continue until terminated by two years' written notice by SEPA or the respective member. Four of our members gave notice to terminate their contracts with SEPA, with negotiated termination dates of March 31, 2019 (34 megawatts) and December 31, 2019 (13 megawatts). A fifth member has agreed to purchase an additional 5 megawatts beginning August 1, 2020. In 2017,2018, the aggregate SEPA allocation to the members was 618 megawatts plus associated energy. The availability of energy under these contracts is significantly affected by hydrologic conditions, including lengthy droughts. Each member must schedule its energy allocation, and each member, other than Flint, has designated us to perform this function. Pursuant to a separate agreement, we schedule, through Georgia System Operations, 37 of our members' SEPA power deliveries. Further, each member may be required, if certain conditions are met, to contribute funds for capital improvements for U.S. Army Corps of Engineers projects from which its allocation is derived in order to retain the allocation.

Smarr EMC

    Smarr EMC is a Georgia electric membership corporation owned by 35 of our 38 members. Smarr EMC owns two combustion turbine facilities with aggregate capacity of 728731 megawatts. The 35 members participating in these two facilities purchase the output of those facilities pursuant to separate take-or-pay power purchase agreements that will continue until terminated by one year's written notice by Smarr EMC or the respective member.

Green Power EMC

    Each of our members is also a member of Green Power Electric Membership Corporation, a power supply cooperative specializing in the purchase of renewable energy for its members. Green Power EMC currently purchases energy from 119120 megawatts of low-impact hydroelectric, landfill gas, wood-waste biomass and solar facilities, with an additional 464 megawatts under contract and under construction, with plans to purchase more in the future. Included in this total is energy purchased from Green Power Solar, a for-profit subsidiary of Green Power EMC, which has leased, with an option to purchase, 8 megawattsnine solar facilities with a total of solar facilities.9 megawatts.

Georgia Energy Cooperative

    Fifteen of our members are members of Georgia Energy Cooperative, An Electric Membership Corporation, which owns a 100 megawatt gas turbine facility and also provides other services to its members.

Other Member Resources

    Our members obtain their remaining power supply requirements from various sources. Thirty-one members are parties to requirements contracts with third parties for some or all of their incremental power needs. The other members use a portfolio of short-term and long-term power purchase contracts to meet their incremental requirements. These requirements contracts and long-term power purchase contracts have remaining terms ranging from 54 to 2423 years.

    These other purchases include 156158 megawatts from solar facilities under long-term contracts.contracts, with an additional 203 megawatts under construction.

    We have not undertaken to obtain a comprehensive list of member power supply resources. Any of our members may have committed or may commit to additional power supply obligations not described above.

    For information about members' activities relating to their power supply planning, see "OGLETHORPE POWER CORPORATION – Competition" and"OUR POWER SUPPLY RESOURCES – Future Power Resources." In addition to future power supply resources that we may construct or acquire for our members, the members will likely also continue to acquire future resources from other suppliers, including suppliers that may be owned by members.

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REGULATION

Environmental

General

    As an electric utility, we are subject to various federal, state and local environmental laws. Air emissions, water discharges and water usage are extensively controlled, closely monitored and periodically reported. The manner in which various types of wastes can be stored, transported and disposed is also broadly regulated.

    In general, environmental requirements are becoming increasingly stringent. Although we have installed environmental control systems at our plants to ensure continued compliance with existing requirements, including systems to reduce emissions of sulfur dioxide, nitrogen oxides, mercury and other pollutants at Plants Scherer and Wansley, new requirements could be imposed. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities. Failure to comply with these requirements could result in civil and criminal penalties and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to comply with these requirements, it would constitute a default under those debt instruments. Although it is our intent to comply with current and future regulations we cannot provide assurance that we will always be in compliance.

    Our capital expenditures and operating costs continue to reflect expenses necessary to comply with environmental standards. For further discussion of expected future capital expenditures to comply with environmental requirements and regulations, see"MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS –Financial Condition –Capital Requirements –Capital Expenditures."

Air Quality

    Environmental concerns of the public, the scientific community and government officials have resulted in legislation and regulation that has had and will continue to have a significant impact on the electric utility industry. The most significant environmental legislation for us continues to be the Clean Air Act, which regulates emissions of sulfur dioxide, nitrogen oxides, particulate matter, greenhouse gases and other pollutants from affected electric utility units, including the coal-fired units at Plants Scherer and Wansley. The Environmental Protection Agency, or EPA, has actively regulated emissions under the Clean Air Act and the following are the most significant ongoing Clean Air Act-related actions that affect or may affect our business.

    Regulatory Reform.    Through a series of Executive Orders, the Trump Administration is requiring many federal agencies, including EPA, to review their regulations and make recommendations regarding the repeal, replacement or modification of certain regulations. Regulations that (i) adversely affect jobs, (ii) are outdated, unnecessary or ineffective, (iii) impose costs exceeding benefits or (iv) interfere with regulatory reform initiatives and policies are to be identified for further action. Pursuant to an Executive Order entitled "Promoting Energy Independence and Economic Growth," EPA has undertaken a number of actions to reconsider and in some cases repeal existing regulations. Where appropriate, reference to such actions are made in the context of the specific regulatory programs discussed below. We cannot predict EPA's actions regarding these regulatory reforms or the effects from any litigation that may result from this extensive effort.

National Ambient Air Quality Standards and Nonattainment Updates.    Pursuant to the Clean Air Act, EPA sets National Ambient Air Quality Standards (NAAQS) for six common air pollutants: particulate matter, ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen dioxide and lead. EPA will periodically review the various NAAQS to determine whether any standards should be made more stringent. In 2015, EPA lowered NAAQS for ground-level ozone and Georgia submitted its proposed designations, recommending that only eight counties be designated nonattainment, with the remainder classified as attainment or unclassifiable. Nonattainment is defined as having air quality worse than the NAAQS as defined in the Clean Air Act and amendments of 1990. Late in 2017, EPA concurred with Georgia's recommendations and plans to formally proposeproposed such designations for Georgia later this year. Once finalized,which became effective in 2018. In December 2018, EPA published a final rule implementing the 2015 NAAQS standards for ozone regulation and updating requirements that states must meet when creating a State Implementation Plans (SIP). The SIP addresses the eight counties identified by Georgia and accepted by EPA as nonattainment. Georgia now must revise its State Implementation Plan (SIP)SIP to demonstrate processes to bring these eight counties into attainment.

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Measures taken could affect sources located within the designated eight counties or sources in surrounding counties if those emissions are deemed to contribute to the nonattainment status of this new Atlanta ozone nonattainment area.

    In 2017, EPA redesignated to attainment all of the counties that were part of the 2008 eight-hour Atlanta ozone nonattainment area. EPA also took action in 2017 to designate nonattainment areas for other NAAQS, such as the 2010 one-hour SO₂sulfur dioxide NAAQS, where all counties in Georgia except Floyd County were designated as attainment/unclassifiable, and the

nitrogen dioxide NAAQS, where EPA proposed no further changes to the standards. While our coal-fired plants have installed control systems for the current suite of NAAQS, the implementation of new or revised NAAQS could lead to additional compliance requirements. The costs of any additional pollution control equipment that could be required because of new or revised NAAQS cannot be determined at this time.

    Cross State Air Pollution Rule.    To address the interstate transport of ozone and fine particulate matter, EPA finalized the Cross State Air Pollution Rule (CSAPR) in 2011, imposing cap and trade programs for sulfur dioxide and nitrogen oxides emissions on fossil fuel-fired electric generating units located in twenty-eight states, including Georgia. EPA has adopted specific trading programs to address these emissions and Georgia is subject to three distinct CSAPR trading programs. Currently, we believe that sufficient controls have been installed on our units, including the co-owned units at Plants Scherer and Wansley, such that compliance with the current CSAPR, including all allowance programs, can be maintained.

    Mercury and Air Toxics Standards and State Mercury Rule.    In December 2011, EPA finalized its Mercury and Air Toxics Standards (MATS), which established maximum achievable control technology limits for certain hazardous air pollutants at coal and oil-fired electric generating units. For coal units, the rule sets stringent emission limits to control various hazardous air pollutants such as mercury, non-mercury metals and acid gases and work practice standards to control organics and dioxins. Our affected generating units, which include our co-owned units at Plants Wansley and Scherer, must comply with MATS. In 2015, the U.S. Supreme Court ruled that EPA must consider costs before finalizing MATS and remanded the rule back to EPA for further rulemaking consistent with its opinion. In 2016, EPA released a supplemental finding that it is appropriate and necessary to regulate hazardous air pollutants from coal and oil-fired electric generating units, and that MATS is reasonable. Cases challenging this determination are pending in the U.S. Circuit Court of Appeals for the District of Columbia Circuit, and have been delayed pending EPA reconsideration of the supplemental finding. EPA published a proposed rule in 2018 reconsidering the 2016 supplemental finding. We cannot predict the outcome of this proposed rule or any related litigation concerning MATS, but even if MATS is ultimately overturned, we would still need to comply with Georgia's "multi-pollutant" rule which requires operation of existing controls at Plants Wansley and Scherer.

    Startup, Shut-down or Malfunction.    In 2015, EPA published a rule requiring 36 states, including Georgia, to revise their SIPs relating to excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). Georgia finalized a state rule and submitted a corresponding SIP revision to EPA prior to the applicable deadlines. However, Georgia's revised rule and SIP revision will not become effective unless EPA approves the SIP submittal, which has not occurred. EPA has delayed current litigation challenging the rule while it reconsiders these standards as part of its regulatory reform review.standards. While EPA may withdraw or change the rule, we cannot predict the ultimate outcome of this rulemaking or any related litigation.

    Air Quality Summary.    We believe that the controls installed at Plants Scherer and Wansley generally meet the requirements described above. Subsequent developments, including litigation and the implementation approaches selected by EPA and Georgia could require significant capital expenditures and increased operating expenses at certain of our generating facilities, particularly Plants Scherer and Wansley.

Carbon Dioxide Emissions and Climate Change

    Several of the Obama Administration's actions to limit carbon dioxide emissions have been curtailed by the Trump Administration. Some of the actions that could potentially have a direct effect on our operations are summarized below. Emissions of carbon dioxide from our plants totaled 10.911.1 million short tons in 2017, as compared to 12.9 million short tons in 2016.

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    After the U.S. Supreme Court ruled in 2007 that certain greenhouse gases, including carbon dioxide, are pollutants which EPA has the authority to regulate under the Clean Air Act, EPA determined that regulation was needed. Beginning in 2009, EPA issued a series of rules that apply the Clean Air Act Prevention of Significant Deterioration and Title V permitting programs to stationary source emissions of greenhouse gases. In 2015, EPA published a series of rules, known as the Clean Power Plan (CPP), which was one of the most significant regulatory actions to reduce greenhouse gas emissions. In the CPP, EPA established New Source

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Performance Standards (NSPS) for new, modified or reconstructed fossil fuel-fired electric generating units. For existing fossil fuel-fired electric generating units, EPA established guidelines for the states to follow in developing final NSPS for such units. Those guidelines became uniform national emission rates for existing units that states were required to incorporate into state rules and performance standards. A lynchpin of the CPP was EPA's interpretation that it could establish emissions guidelines beyond the fence line of regulated sources and require system-wide reductions in carbon dioxide emissions from source owners and operators. In 2016, the U.S. Supreme Court stayed the CPP pending resolution of litigation challenging the CPP in the U.S. Court of Appeals for the District of Columbia Circuit including any appeal to the Supreme Court. That litigation has been delayed by EPA, pending reconsiderationthe proposed replacement of the CPP rule.

    In October 2017,August 2018, the EPA issued a proposed aAffordable Clean Energy (ACE) rule to repealreplace the CPP,Clean Power Plan. The final ACE rule is expected in large part onspring of 2019. The proposed rule is an "inside the revised interpretationfence" regulation that emission guidelinesdefines the Best System of Emissions Reduction (BSER) for carbon dioxide as heat rate improvement measures, or a highly efficient facility. The proposed ACE rule gives states flexibility in using the BSER to set the standard of performance for affected existing sourcesunits on a source-specific basis and for establishing compliance requirements and deadlines. States are limitedallowed to consider remaining useful life and other factors in setting standards of performance for affected units. Because heat rate improvement measures may trigger New Source Review (NSR), the steps source owners and operators can take atproposed ACE rule also modifies the regulated source. In December 2017, EPA also issued an Advance NoticeNSR program by adding a "maximum hourly emission increase" test that reduces the likelihood of Proposed Rulemaking seeking information on the steps existing sources could take that would be consistent with this revised interpretation.triggering NSR requirements.

    EPA may take other actions in the future to address the emissions of greenhouse gases from our units. For example, EPA may seek to revisit and perhaps reconsideris currently reconsidering its NSPS for new and modified fossil fuel-fired electric generating units. We cannot predict the outcome of regulatory changes, agency actions, including but not limited to the withdrawal or revision of guidance, or executive orders related to climate change, nor can we predict the outcome or effect of possible litigation resulting from any of these actions.

    In November 2015, the Paris Agreement was adopted at the United Nations 21^st International Climate Change Conference. It established a non-binding universal framework for addressing greenhouse gas emissions based on nationally determined commitments as well as a process for increasing those commitments going forward. On June 1, 2017, President Trump announced that the U.S. would cease all participation in the 2015 Paris Agreement, stating that the accord would undermine the U.S. economy and put it at a permanent disadvantage. The Trump Administration continues to be committed to withdrawing from the agreement. We are unable to determine the ultimate impact, if any of this action on our operations or costs.

Coal Combustion Residuals and Steam Electric Power Generating Effluent Guidelines

    In 2015, EPA published a coal combustion residuals (CCR) rule to regulate CCRs from electric utilities as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act. The rule contains requirements for structural integrity assessments, groundwater monitoring, location siting, composite lining, inactive units, closure and post closure, beneficial use recycling, design and operating criteria, recordkeeping, notification, and internet posting for new and existing CCR landfills, CCR surface impoundments and lateral expansions of CCR facilities. In March 2018 EPA published a proposed rule to update the 2015 CCR rule. A final rule is expected later in 2018. In 2015, the EPA also finalized a rule to revise the effluent limitations guidelines that apply to certain wastewater discharges from fossil fuel-fired steam electric power plants, including our co-owned Plants Wansley and Scherer. In 2017, EPA postponed certain compliance dates related to the effluent limitations guidelines.

    On July 30, 2018, the EPA published the first two final rules in the Federal Register that revised a portion of its 2015 CCR rule. The revisions provide relief from several mandatory closure requirements and provide significant flexibility for facility owners to implement the CCR disposal and management requirements. Then, on August 21, 2018, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued a decision that addressed all remaining issues raised by industry and environmental groups in the ongoing CCR litigation. In its decision, the D.C. Circuit vacated and remanded portions of EPA's 2015 CCR rule. Among other things, the court ruled that the current federal CCR requirements for unlined and clay-lined surface impoundments must be revised to address potential risks of leakage. On March 13, 2019 the D.C. Circuit granted EPA's motion for remand without vacatur of the revised

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CCR rule. EPA is required to issue a rulemaking to incorporate the D.C. Circuit's decision in August 2018. No other litigation related to CCR is pending. We cannot predict the outcome of any future EPA rulemaking efforts relating to CCR plant operations at this time.

    In 2016, and in response to EPA's CCR rulemaking, the Georgia Environmental Protection Division added specific provisions for CCR wastes to its existing solid waste management rules. These rules contain EPA's CCR rule requirements as well as further requirements for CCR wastes in Georgia. The additional requirements are administered through a state permit system. Citizen groups retain the authority to enforce federal CCR requirements. At this point, Georgia's CCR regulations are not anticipated to have a material impact on our compliance obligations under the federal CCR rule. However, we cannot predict the impact of any future changes to the CCR or the effluent limitations guidelines.

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    In 2015,    Georgia Power announced that it is preparing a schedule to close existing ash ponds at all of its Georgia coal-fired facilities, including at our co-owned Plants Scherer and Wansley. In 2016, Georgia Power furtherhas announced that it would cease sending CCR to all of its ash ponds in Georgia within three years.including at our co-owned facilities Plants Scherer and Wansley in 2019. It also announced that it would close the ash ponds in place using advanced engineering methods at Plants Wansley and Scherer, among other locations. The initial closure plans Georgia Power filed with the Georgia Environmental Protection Division estimated closing activities to be completed in 2026 for Plant Wansley and 2031 for Plant Scherer. Our current estimated expenditures for the settlement of related asset retirement obligations are approximately $173$400 million to $550 million (in year of expenditure dollars) for the closure and post-closure of existing coal ash ponds. See Note 1 of Notes to Consolidated Financial Statements. In addition, preliminarycurrent estimates suggest that our capital expenditures to comply with the CCR rule and effluent limitations guidelines will be approximately $273$325 million to $350 million for conversion to dry ash handling, landfill construction and wastewater treatment. More definitive cost estimates will continue to be developed as the process of rule evaluation, compliance approach and design and construction implementation proceeds. The ultimate impacts associated with the federal and state CCR rules and the federal effluent limitations guidelines, any changes EPA may make to those rules, and any related litigation challenging such rules cannot be determined at this time.

Water Use and Wastewater Issues

    In 2008, the Georgia legislature adopted a comprehensive State Water Plan that lays out statewide policies, management practices and guidance for regional water planning in Georgia. In 2011, the Georgia Environmental Protection Division adopted regional water plans that were developed pursuant to the State Water Plan. Regional plans include resource assessments, estimates of current and future water needs and management practices. Updated draft regional water plans have been developed and were issued for public notice and comment in 2017. Georgia will consider the information contained in regional water plans (including any updated plans) when making water use permitting decisions under existing state law. The state water planning process may lead to new or revised regulations for water users in the future. Because power generation is generally dependent on water usage, the regional water plans and any future regulations or other enforceable requirements developed in connection with the State Water Plan may have substantial effects on the operations of our facilities or future facilities that we construct or acquire. The impacts of future regulations or revisions to regional water plans on our facilities or future facilities cannot be determined at this time.

    In 2015, the U.S. Court of Appeals for the Sixth Circuit stayed a final rule published jointly by EPA and the U.S. Army Corps of Engineers that revised the regulatory definition of waters of the U.S. for all Clean Water Act programs. The final rule would have significantly expanded the scope of federal jurisdiction under the Clean Water Act. Although the rule was not expected to have a substantial impact on our existing operations, it would likely have increased permitting and regulatory requirements and costs associated with the siting and permitting of new facilities. In July 2017, EPA proposed a two-step process to address the stayed rule.rule and followed that proposal with a supplemental proposed rule in June 2018. The first step replaces the 2015 regulations that defined waters of the U.S. with those that were in effect prior to the 2015 rule. In the second step, EPA states that it will pursueproposed a formal rulemaking to substantively re-evaluaterule in December 2018 replacing the 2015 ruledefinition with a revised definition that clarifies and may substantially revise that rule.narrows the scope of federal authority under the Clean Water Act. We cannot determine the ultimate impact of the 2015 rule, any change to that rule or any litigation challenging that rule or any replacement rule at this time.

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Other Environmental Matters

    We are subject to other environmental statutes including, but not limited to, the Georgia Water Quality Control Act, the Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act, and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations will have a material impact on our financial condition or results of operations. Changes to any of these laws, however, could affect many areas of our operations. Although compliance with new environmental legislation could have a significant impact on those operations, such impacts cannot be fully determined at this time and would depend in part on the final legislation and the development of implementing regulations.

    As an owner, co-owner and/or operator of generating facilities, we are also subject, from time to time, to

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claims relating to operations and/or emissions, including actions by citizens to enforce environmental regulations and claims for personal injury due to such operations and/or emissions. Likewise, actions by private citizen groups to enforce environmental laws and regulations are becoming increasingly prevalent. We cannot predict the outcome of current or future actions, our responsibility for a share of any damages awarded, or any impact on facility operations. We do not believe, however, that current actions will have a material adverse effect on our financial position, results of operations or cash flows.

    While we will continue to exercise our best efforts to comply with all applicable regulations, there can be no assurance that we will always be in compliance with all current and future environmental requirements. Failure to comply with existing and future requirements, even if this failure is caused by factors beyond our control, could result in civil and criminal penalties and could cause the complete shutdown of individual generating units not in compliance with these regulations. Any additional federal or state environmental restrictions imposed on our operations could result in significant additional compliance costs, including capital expenditures. Such costs could affect future unit retirement and replacement decisions and may result in significant increases in the cost of electric service. The cost impact of future legislation, regulation, judicial interpretations of existing laws or regulations, or international obligations will depend upon the specific requirements thereof and cannot be determined at this time.

Nuclear Regulation

    We are subject to the provisions of the Atomic Energy Act of 1954 (the Atomic Energy Act), which vests jurisdiction in the Nuclear Regulatory Commission over the construction and operation of nuclear reactors, particularly with regard to certain public health, safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the Nuclear Regulatory Commission to consider the environmental impact of a facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by the Nuclear Regulatory Commission. All aspects of the construction, operation and maintenance of nuclear power plants are regulated by the Commission. From time to time, new Commission regulations require changes in the design, operation and maintenance of existing nuclear reactors. Operating licenses issued by the Commission are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the Commission determines that the public interest, health or safety so requires. The operating licenses issued for each unit of Plants Hatch and Vogtle expire in 2034 and 2038, and 2047 and 2049, respectively.

    The Nuclear Regulatory Commission issued combined construction permits and operating licenses that allow the completion of construction and operation of two additional units at Plant Vogtle. See "OUR POWER SUPPLY RESOURCES –Future Power Resources –Plant Vogtle Units No. 3 and No. 4."

    Pursuant to the Nuclear Waste Policy Act of 1982, the federal government has the responsibility for the final disposal of commercially produced high-level radioactive waste materials, including spent nuclear fuel. This act requires the owner of nuclear facilities to enter into disposal contracts with the Department of Energy for such material.

    Contracts with the Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, has

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successfully pursued and continues to pursue legal remedies against the Department of Energy for breach of contract. See Note 1 of Notes to Consolidated Financial Statements for information regarding the status of this litigation.

    In November 2013, the U.S. District Court for the District of Columbia ordered the Department of Energy to cease collecting spent fuel depositary fees from nuclear power plant operators until such time as the Department of Energy either complies with the Nuclear Waste Policy Act of 1982 or until the U.S. Congress enacts an alternative waste management plan. We discontinued paying the fee of approximately $9.2 million annually, based on our ownership interests, in June 2014.

    Existing on-site dry storage facilities at Plants Hatch and Vogtle can be expanded to accommodate spent fuel through the expected life of each plant, including Vogtle Units No. 3 and No. 4.

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    For information concerning nuclear insurance, see Note 10 of Notes to Consolidated Financial Statements. For information regarding the Nuclear Regulatory Commission's regulation relating to decommissioning of nuclear facilities and regarding the Department of Energy's assessments pursuant to the Energy Policy Act for decontamination and decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to Consolidated Financial Statements.

Federal Power Act

General

    Pursuant to the Federal Power Act, the Federal Energy Regulatory Commission is the federal agency that regulates the nation's bulk power system. We are subject to certain rules and regulations under the Federal Power Act; however, as a borrower from the Rural Utilities Service, we are exempted from certain Federal Energy Regulatory Commission regulations, including rate regulation.

Rocky Mountain

    We are subject to the hydropower licensing provisions of the Federal Power Act. Rocky Mountain is a hydroelectric project subject to licensing by the Federal Energy Regulatory Commission. The currently effective Federal Energy Regulatory Commission license to operate the Rocky Mountain project expires in 2026. See "PROPERTIES –Generating Facilities" and "–" – The Plant Agreements –Rocky Mountain" for additional information.

    Upon or after the expiration of the license, the United States Government, by act of Congress, may take over the project, or the Federal Energy Regulatory Commission may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken. The Federal Energy Regulatory Commission may grant relicenses subject to certain requirements that could result in additional costs. If the Federal Energy Regulatory Commission does not act on the new license application prior to the expiration of the existing license, the commission is required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued.

    We anticipate making a timely application for a new license for the Rocky Mountain project.

Energy Policy Act of 2005

    The Energy Policy Act of 2005 amended the Federal Power Act to authorize the Federal Energy Regulatory Commission to establish an electric reliability organization to develop and enforce mandatory reliability standards and to establish clear responsibility for the commission to prohibit manipulative energy trading practices. In 2006, the Federal Energy Regulatory Commission certified the North American Electric Reliability Corporation, or NERC, as the electric reliability organization. The mandatory reliability standards developed by NERC and approved by the Federal Energy Regulatory Commission impose certain operating, coordination, record-keeping and reporting requirements on us. NERC has delegated day-to-day enforcement of its responsibilities to regional entities and SERC Reliability Corporation is the regional entity to enforce reliability compliance in sixteen central and southeastern states, including Georgia. These entities have the authority to issue fines and penalties for violations of these standards.

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    As a generator owner and generator operator, we are subject to certain of these mandatory reliability standards. We have established a comprehensive formal compliance program to establish, monitor, maintain and enhance our commitment to electric reliability compliance. This program includes comprehensive cyber security elements designed to protect and preserve our critical information and energy infrastructure systems. Although we intend to comply with all currently effective and enforceable reliability standards, we cannot provide assurance that we will always be in compliance. We are obligated to maintain and retain evidence of compliance with specific requirements. SERC Reliability Corporation also regularly monitors us for compliance with reliability standards. We expect that existing reliability standards will continue to be refined and that new reliability standards will be developed or adopted.

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ITEM 1A.    RISK FACTORS

    The following describes the most significant risks, in management's view, that may affect our business and financial condition or the value of our debt securities. This discussion is not exhaustive, and there may be other risks that we face which are not described below. The risks described below, as well as additional risks and uncertainties presently unknown to us or currently not deemed significant, could negatively affect our business operations, financial condition and future results of operations.

Our participation in the development and construction of Vogtle Units No. 3 and No. 4 could have a material impact on our financial condition and results of operations.

    We are 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 reached commercial operation using advanced designs, such as the Westinghouse AP1000 design, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also rely on Georgia Power and Southern Nuclear as our agents for the oversight of the construction of the additional units at Plant Vogtle and do not exercise direct control over the construction process.

    Our current project budget for As of December 31, 2018, our total investment in the additional Vogtle units was approximately $3.9 billion.

    In mid-2018, Georgia Power advised us that it became aware that the estimated future Vogtle project costs were projected to exceed the corresponding budgeted amounts included in its seventeenth VCM report. Upon discovery of these variances, the Co-owners requested Southern Nuclear perform a full cost analysis and reforecast the cost to complete the project and engaged a third party to independently assess this analysis, forecast and existing project controls for identifying budget variances. Following this analysis, Georgia Power proposed an increased construction budget and included a revised estimate to complete in its nineteenth VCM report filed with the Georgia Public Service Commission in August 2018. This revised estimate included an approximate $1.5 billion increase in capital costs (our 30% share is approximately $450 million) and a project-level contingency of $800 million (our 30% share is $240 million). The increase in the revised budget was primarily attributable to Bechtel and subcontractor construction costs, including craft labor incentives, as well as expenses for project management, oversight and support. The scheduled in-service dates of November 2021 and November 2022 for Vogtle Units No. 3 and No. 4, respectively, did not change in connection with these budget revisions.

    Further, Georgia Power informed the Public Service Commission in its nineteenth VCM report that it did not intend to seek rate recovery for its proportionate share of the additional capital costs identified in that report. As a result of Georgia Power's decision not to seek rate recovery of its allocation of these costs and the increased construction budget, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 were required to vote to continue construction.

    In September 2018, the Co-owners voted to continue construction of Vogtle Units No. 3 and No. 4. In connection with this vote, the Co-owners entered into the Term Sheet which was later memorialized by the Global Amendments in February 2019. We also approved a revised budget of $7.5 billion for our 30% ownership interest. The impact of the additional project costs on our budget was substantially mitigated by nearly $500 million of contingency included in our prior budget. As with our prior budgets and consistent with our conservative budget practices, our revised budget includes a separate Oglethorpe-level contingency amount in addition to capital costs, allowance for funds used during construction, and a contingency amount, is $7.0 billion and we expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our $7.0 billion budget is net of payments we received from Toshiba under the Guarantee Settlement Agreement. Certain events have materially delayed the original commercial operation dates and increased the original project budget. The most significant of these relate to Westinghouse's filing for bankruptcy protection under Chapter 11our allocation of the United States Bankruptcy Code and its subsequent rejection of the substantially fixed price EPC Agreement.project-level contingency.

    On January 11, 2018, the Georgia Public Service Commission entered an order regarding a series of actions related to Vogtle Units No. 3 and No. 4 that the Public Service Commission approved on December 21, 2017. Among other actions, the Public Service Commission (i) accepted Georgia Power's recommendation that construction of Vogtle Units No. 3 and No. 4 be completed, with Southern Nuclear serving as construction manager and Bechtel as primary contractor and (ii) approved the revised schedule placing Unit No. 3 in service in November 2021 and Unit No. 4 in service in November 2022. In its January 11, 2018 order, the Public Service Commission stated if certain assumptions upon which Georgia Power's recommendations were based do not materialize, both the Public Service Commission and Georgia Power reserve the right to reconsider the decision to continue construction. Parties have filed two petitions in Fulton County Superior Court for judicial review of the Public Service Commission's January 11, 2018 order. Georgia Power has stated that it believes these appeals have no merit; however, an adverse outcome in one or both of these appeals could have a material impact on our financial condition and results of operations.

    As construction continues, we remain subject to construction risks and no longer have the benefit of the substantially fixed price EPC Agreement which means that weWe and the other Co-owners are responsible for all construction costs based on our ownership percentages. Factors that could lead to further cost increases and schedule delays or even the inability to complete this project include:

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performance by Georgia Power as agent for the Co-owners and performance by Southern Nuclear as construction manager;



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performance by Bechtel under the Bechtel Agreement as well as subcontractor and supplier performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission;



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shortages, increased costs or inconsistent quality of labor, equipment and materials;



•

changes in labor costs, availability and productivity;

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performance by Westinghouse under the Services Agreement;



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loss of access to intellectual property rights necessary to construct or operate the project;



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shortages and/or inconsistent quality of equipment, materials and labor;

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increases in our cost of debt financing as a result of changes in market interest rates or as a result of construction schedule delays;



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unforeseen engineering or design problems;



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delays in start-up activities (including major equipment failure and system integration) and/or operational performance;



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operational readiness, including specialized operator training;



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erosion of public and policymaker support;



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liens on the project;



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contract disputes;



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permits, approvals and other regulatory matters;



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unanticipated increases in the costs of materials;



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changes in project design or scope;



•

impacts of new and existing laws and regulations, including environmental laws and regulations;



•

adverse weather conditions; and



•

work stoppages.

    On November 2, 2017,However, pursuant to the Global Amendments, Georgia Power agreed to mitigate certain financial exposure for the other Co-owners. In the event that construction costs exceed the EAC in the nineteenth VCM report by more than $800 million up to $2.1 billion, Georgia Power will be responsible for an increasing percentage of construction costs, subject to exceptions, up to a maximum of an additional $180 million, and each Co-owner would maintain its existing ownership interest. In the event that the EAC exceeds the EAC in the nineteenth VCM report by more than $2.1 billion, each of the Co-owners, amended the Joint Ownership Agreementsother than Georgia Power, will have a one-time option to provide that holderstender a portion of at least 90%its ownership interest to Georgia Power in exchange for Georgia Power's agreement to pay 100% of such Co-owner's remaining share of construction costs in excess of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction upon the occurrence of certain adverse events. As we are a 30% ownerEAC in the Vogtle project, we, along withnineteenth VCM report plus $2.1 billion. This option to tender a portion of our interest to Georgia Power and the Municipal Electricity Authority of Georgia, will all needupon such a budget increase would allow us to determine to move forwardfreeze our construction budget associated with the Vogtle project uponin exchange for a portion of our 30% ownership interest.

    Georgia Power and Southern Nuclear are in the occurrenceprocess of anyvalidating recent construction progress in comparison to the projected schedule and verifying and updating quantities of those adverse events. In the event the Co-owners determine notcommodities remaining to proceed with the project following such an event, our proportionate share of the Co-owners' cancellation costs are estimatedinstall, labor productivity, and forecasted staffing needs. This verification process, led by Southern Nuclear, is expected to be approximately $230 million. Ascompleted during the second quarter of December 31, 2017,2019. Although the verification is not complete, we currently do not anticipate any material changes to our total investment inproject budget of $7.5 billion or the additional Vogtle units was approximately $2.9 billion, netPublic Service Commission approved in-service dates of payments we received from Toshiba underNovember 2021 and November 2022 as a result of this verification process. However, the Guarantee Settlement Agreement. If the project is cancelled, we would seek regulatory accounting treatmentcurrent schedule being utilized to amortize our investment inmanage construction at the Vogtle site, which targets in-service dates in advance of November 2021 and November 2022, may be adjusted to reflect updated information provided by the verification process. The ultimate impact on cost and schedule, if any, will not be known until the verification process is completed. Georgia Power has stated that it is required to report the results and any project over a long-term period which would requireimpacts to the approval of our board of directors and the Rural Utilities Service.Public Service Commission by May 15, 2019.

    As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors,vendors; labor productivity, and availability, and/or cost escalation; procurement, fabrication, delivery, assembly and/or installation and installationtesting, including any required engineering changes, of plant systems, structures and components,components; or other issues could further impact the projected schedule and cost. Aspects ofMonthly construction production targets required to maintain the Westinghouse AP1000 design are based on new technologiescurrent project schedule will continue to increase significantly throughout 2019. To meet these increasing monthly targets, existing craft construction productivity must improve and commercial operation of this design has yet toadditional craft laborers must be tested.retained and deployed.

    There have also been technical and procedural challenges to the construction and licensing of these unitsVogtle Units No. 3 and additional challengesNo. 4 at the federal and state level and additional challenges may arise. Processes are in place that are designed to assure compliance with the requirements specified in the Westinghouse Design Control Document and the combined construction and operating licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory

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Commission. Various design and other licensing-based compliance matters, including the timely resolution of inspections, tests, analyses, and acceptance criteria and the related approvals by the Nuclear Regulatory Commission, may arise, as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners.

    In late 2018, the first four nuclear units to utilize Westinghouse's AP1000 technology began commercial operation in China. Recently one of these units reportedly experienced a failure of one of its four reactor coolant pumps and is not operating pending determination of the cause of the failure and replacement of the pump. The other three nuclear units remain in operation.

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

    The Global Amendments provide that Georgia Power may cancel the project at any time in its sole discretion. In the event that Georgia Power determines to cancel the project or fewer than 90% of the Co-owners vote to continue construction upon the occurrence of a subsequent project adverse event, we and the other Co-owners would assess our options for the Vogtle project. If the investment were to be written off, we would seek regulatory accounting treatment to amortize the investment over a long-term period, which requires the approval of our board of directors, and we would submit the regulatory accounting treatment details to the Rural Utilities Service for its approval. Further, if Georgia Power or the Co-owners decided to cancel the project, the Department of Energy would have the discretion to require that we repay all amount outstanding under the loan guarantee agreement over a five-year period.

    MEAG is currently involved in litigation with JEA regarding a power purchase agreement for approximately 9% of the total output of Vogtle Units No. 3 and No. 4 for the first 20 years of operation. This litigation could impact MEAG's ability to finance the MEAG Power SPVJ portion of its interest in Vogtle Units No. 3 and No. 4; however, there are provisions in the Joint Ownership Agreements that permit the other Co-owners to fund construction in the event that one Co-owner fails to fund its proportionate costs. MEAG and Georgia Power have entered into a funding agreement for Georgia Power to provide MEAG up to an additional $300 million of financing. JEA has publicly stated that it intends to honor its obligations under the power purchase agreement unless relieved of its obligations by a court. MEAG has stated that it believes JEA's claims are without merit and that it will prevail in these proceedings.

    The ultimate outcome of these matters cannot be determined at this time; however, these risks could continue to impact the in-service dates and cost of the additional units at Plant Vogtle which would increase the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.

Our access to, and cost of, capital could be adversely affected by various factors, including market conditions, limitations on the availability of federally-guaranteed loans and our credit ratings. Significant constraints on our access to, or increases in our cost of, capital may limit our ability to execute our business plan by impacting our ability to fund capital investments and could adversely affect our financial condition and results of operations.

    We rely on access to external funding sources as a significant source of liquidity for capital expenditures not satisfied by cash flow generated from operations.

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Unlike most investor-owned utilities, electric cooperatives cannot issue equity securities and therefore rely almost entirely on debt financing.

    In connection with our share of the cost to construct the additional units at Plant Vogtle, in 2014 we obtained a loan

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from the Federal Financing Bank and a related loan guarantee from the Department of Energy to fund up to $3.1 billion of eligible project costs through 2020. As of December 31,costs. Following Westinghouse's bankruptcy in 2017, we had advanced $1.7 billionour ability to request further advances under this loan had been restricted pending satisfaction of certain conditions. On March 7, 2019, we and the Department of Energy entered into an amendment and waiver to the loan guarantee agreement, which allowed us to receive an advance of $585 million, increasing our total borrowings under the original loan to $2.4 billion. On March 22, 2019, we obtained an additional $1.6 billion loan from the Federal Financing Bank and amended and restated the loan guarantee agreement with the Department of Energy to increase the aggregate funding amount available to us to $4.7 billion of eligible project costs and permit us to advance the remaining amount available under the original loan.

    Access to the committed funds under this loanthese loans requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third parties related to the Vogtle project to comply with certain laws. 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. While not assured, we expect to satisfy these conditions in the second quarter of 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. In addition, the occurrence of certain adverse events would give the Department of Energy discretion to require that we repay all amounts outstanding under the loan guarantee agreement over a five-year period. In the event that we are unable to draw the full amount of this loanthese loans or are required to repay amounts outstanding over a five year period, we expect that we would finance those project expenditures in the capital markets which would likely be at a higher cost.

    We have received a conditional commitment from the Department of Energy for approximately $1.6 billion of additional loan guarantees for eligible project costs. This conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. Final approval and issuance of the additional loan guarantee by the Department of Energy cannot be assured and is subject to negotiation of definitive agreements, completion of due diligence by the Department of Energy, receipt of any necessary regulatory approvals and satisfaction of other conditions. See Note 7a of Notes to Consolidated Financial Statements for additional information about the terms of the loan guarantee agreement and related conditions.

    Historically, we relied on federal loan programs guaranteed by the Rural Utilities Service, a branch of the U.S. Department of Agriculture, in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of Rural Utilities Service funding levels are subject to the annual federal budget appropriations process, and therefore are subject to uncertainty because of budgetary and political pressures faced by Congress. If the amount of this funding available to us in the future is decreased or eliminated, we would seek alternative sources of debt financing in the traditional capital markets which would likely be at a higher cost.

    Our access to both short-term and long-term capital market funding remains an important factor in our financing plans, particularly in light of the significant amount of projected capital investment. We have entered into multiple credit agreements that provide significant short-term and medium-term liquidity and have successfully accessed the capital markets in the past to satisfy our long-term borrowing needs. We believe that we will be able to maintain sufficient access to the short-term and long-term capital markets based on our current credit ratings. However, our credit ratings reflect the views of the rating agencies, which could change at any point in the future. If one or more rating agencies downgrade us and potential investors take a similar view, our borrowing costs couldwould likely increase and our potential pool of investors, funding sources and liquidity could decrease. In addition, if our credit ratings are lowered below investment grade, collateral calls may be triggered under certain agreements and contracts which would decrease our available liquidity.

    Our borrowing costs are also affected by prevailing interest rates. If interest rates have increased at the time we issue fixed rate debt or reset the interest rates on our variable rate debt, our interest costs will increase and our financial condition and future results of operations could be adversely affected.

    In addition, market disruptions could constrain, at least temporarily, lenders' willingness or ability to perform their obligations under existing credit agreements and our ability to access additional sources of capital on favorable terms or at all. These disruptions include:

•

instability in domestic or foreign financial markets;



•

a tightening of lending and lending standards by banks and other credit providers;



•

the overall health of the energy and financial industries;



•

economic downturns or recessions;

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•

negative events in the energy industry, such as the bankruptcy of an unrelated energy company or the occurrence of a significant natural disaster;