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Supply Resources –Smarr EMC" and"PROPERTIES – Generating Facilities."

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    In 2015,2017, two of our members, CobbJackson EMC and SawneeCobb EMC, accounted for 13.1%14.7% and 10.4%14.3% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2015.2017.

Wholesale Power Contracts

    The wholesale power contracts we have with each member are substantially similar and extend through December 31, 2050 and continue thereafter until terminated by three years' written notice by us or the respective member. Under the wholesale power contracts, each member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs of each of our generation resources and purchased power resources with a term greater than one year. Each wholesale power contract specifically provides that the member must make payments whether or not power is delivered and whether or not a plant has beenresource is completed, delayed, terminated, operable, operating, retired, sold, leased, transferred or is otherwise unavailable. We are obligated to use our reasonable best efforts to operate, maintain and manage our resources in accordance with prudent utility practices.

    We have assigned fixed percentage capacity cost responsibilities to our members for all of our generation and purchased power resources, although not all members participate in all resources. For any future resource, we will assign fixed percentage capacity cost responsibilities only to members choosing to participate in that resource. The wholesale power contracts provide that each member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for approved future resources, whether or not that member has elected to participate in the resource, that are approved by 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. For resources so approved in which less than all members participate, costs are shared first among the participating members, and if all participating members default, each non-participating member is expressly obligated to pay a proportionate share of the default.

    Under the wholesale power contracts, we are not obligated to provide all of our members' capacity and energy requirements. Individual members must satisfy all of their requirements above their purchase obligations from us from other suppliers, unless we and our members agree that we will supply additional capacity and associated energy, subject to the approval requirements described above. In 2015,2017, we supplied energy that accounted for approximately 48%63% of the retail energy requirements of our members. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Member Power Supply Resources."

    Under the wholesale power contracts, each member must establish rates and conduct its business in a manner that will enable the member to pay (i) to us when due, all amounts payable by the member under its wholesale power contract and (ii) any and all other amounts payable from, or which might constitute a charge or a lien upon, the revenues and receipts derived from the member's electric system, including all operation and maintenance expenses and the principal of, premium, if any, and interest on all indebtedness related to the member's electric system.

New Business Model Member Agreement

    The New Business Model Member Agreement that we have with our members requires member approval for us to undertake certain activities. The agreement does not limit our ability to own, manage, control and operate our resources or perform our functions under the wholesale power contracts.

    We may not provide services unrelated to our resources or our functions under the wholesale power contracts if these services would require us to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of the members of our board of directors, 75% of our members, and members representing 75% of our patronage capital. We may provide any other unrelated service to a member so long as (i) doing so would not create a conflict of interest with respect to other members, (ii) the service is being provided to all members or (iii) the service has received the three 75% approvals described above.

Electric Rates

    Each member is required to pay us for capacity and energy we furnish under its wholesale power contract in accordance with rates we establish. We review our rates periodically but are required to do so at least once every year. We are required to revise our rates as necessary so that the revenues derived from our rates, together with our revenues from all other sources, will

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together with our revenues from all other sources, will be sufficient to pay all of the costs of our system, including the payment of principal and interest on our indebtedness, to provide for reasonable reserves and to meet all financial requirements.

    The formulary rate we established in the rate schedule to the wholesale power contracts employs a rate methodology under which all categories of costs are specifically separated as components of the formula to determine our revenue requirements. The rate schedule also implements the responsibility for fixed costs assigned to each member based on each member's fixed percentage capacity cost responsibilities for all of our generation and purchased power resources. The monthly charges for capacity and other non-energy charges are based on our annual budget. These capacity and other non-energy charges may be adjusted by our board of directors, if necessary, during the year through an adjustment to the annual budget. Energy charges reflect the pass-through of actual energy costs, including fuel costs, variable operations and maintenance costs and purchased energy costs. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Summary of Cooperative Operations –Rate Regulation."

    Under the first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The formulary rate is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses we recorded, plus amounts necessary to achieve at least the minimum 1.10 margins for interest ratio. In the event we were to fall short of the minimum 1.10 margins for interest ratio at year end, the formulary rate is designed to recover the shortfall from our members in the following year without any additional action by our board of directors.

    Under our loan agreements with each of the Rural Utilities Service and Department of Energy, changes to our rates resulting from adjustments in our annual budget are generally not subject to their approval. We must provide the Rural Utilities Service and Department of Energy with a notice of and opportunity to object to most changes to the formulary rate under the wholesale power contracts. See "– Relationship with Federal Lenders." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

First Mortgage Indenture

    Our principal financial requirements are contained in the Indenture, dated as of March 1, 1997, from us to U.S. Bank National Association, as trustee (successor to SunTrust Bank), as amended and supplemented, referred to herein as the first mortgage indenture. The first mortgage indenture constitutes a lien on substantially all of our owned tangible and certain of our intangible property, including property we acquire in the future. The mortgaged property includes our owned electric generating plants, the wholesale power contracts with our members and some of our contracts relating to the ownership, operation or maintenance of electric generation facilities owned by us.

    Under our first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The margins for interest ratio is determined by dividing margins for interest by total interest charges on debt secured under our first mortgage indenture. Margins for interest is the sum of:

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our net margins (after certain defined adjustments), plus



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interest charges on all indebtedness secured under our first mortgage indenture, plus



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any amount included in net margins for accruals for federal or state income taxes.

    Margins for interest takes into account any item of net margin, loss, gain or expenditure of any of our affiliates or subsidiaries only if we have received the net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if we have made a payment with respect to the losses or expenditures. In addition, our margins include certain items that are excluded from the margins for interest ratio, such as non-cash capital credits allocation from Georgia Transmission Corporation.

    Under our first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to the distribution, (i) an event of default exists under the first

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mortgage indenture, (ii) our equity as of the end of the

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immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however, will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is at least 30% of our total long-term debt and equities. As of December 31, 2015,2017, our equity ratio was 9.5%9.8%.

    As of December 31, 2015,2017, we had approximately $7.6$8.2 billion of secured indebtedness outstanding under the first mortgage indenture. From time to time, we may issue additional first mortgage obligations ranking equally and ratably with the existing first mortgage indenture obligations. The aggregate principal amount of obligations that may be issued under the first mortgage indenture is not limited; however, our ability to issue additional obligations under the first mortgage indenture is subject to certain requirements related to the certified value of certain of our tangible property, repayment of obligations outstanding under the first mortgage indenture and payments made under certain pledged contracts relating to property to be acquired.

Relationship with Federal Lenders

Rural Utilities Service

    Historically, federal loan programs administered by the Rural Utilities Service, an agency of the United States Department of Agriculture, have provided the principal source of financing for electric cooperatives. Loans guaranteed by the Rural Utilities Service and made by the Federal Financing Bank have been a major source of funding for us. However, the availability and magnitude of Rural Utilities Service loan funds are subject to annual federal budget appropriations, and, thus cannot be assured. Currently, Rural Utilities Service loan funds are subjectdue to increased uncertainty because of budgetary and political pressures faced by Congress.Congress, the availability and magnitude of these loan funds cannot be assured. Congress has authorized the Rural Utilities Service to charge a fee to cover the cost of loan guarantees for baseload generation, if requested by a borrower. The Rural Utilities Service must establish a process to implement this authorization prior to making it available to borrowers. The President's budget proposal for fiscal year 2017 provides for $6.52019, which begins October 2018, proposes a loan program of $5.5 billion, in loans for electric infrastructure, including renewable energy, generation facilities with carbon sequestration, peaking units affiliated with energy facilities that produce electricity from solar, wind and other intermittent sources of energy, environmental improvements to fossil-fueled generation that would reduce air emissions, consistent with any applicable state clean power plan, and grid security enhancements. The budget proposes to expand the same as the current program authority to support renewable and clean energy goals.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, we cannot predict the amount or cost of Rural Utilities Service loans that may be available to us in the future.

    We have a loan contract with the Rural Utilities Service. Under the loan contract, we may have to obtain approval from the Rural Utilities Service or provide the Rural Utilities Service with a notice and an opportunity to object before we take certain actions, including, without limitation,

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significant additions to or dispositions of system assets,



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significant power purchase and sale contracts,



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changes to the wholesale power contracts and the formulary rate contained in the wholesale power contracts, and



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changes to plant ownership and operating agreements.

    As of December 31, 2015,2017, we had $2.6$2.5 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.

    In February 2014, the Rural Utilities Service and certain other rural development agencies within the U.S. Department of Agriculture proposed combined rule changes affecting their implementation of the National Environmental Policy Act. The National Environmental Policy Act requires any federal agency responsible for a major federal action to evaluate the environmental impact of such action and is applicable to the Rural Utilities Service as a result of its financing activities. The proposed rule changes could have resulted in the designation of certain transactions governed by the loan contracts between us or a member and the Rural Utilities Service as major federal actions and therefore could have resulted in added compliance costs or delays in connection with such transactions. However, after

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reviewing comments from numerous stakeholders, including us, on March 2, 2016 a final rule was issued confirming the current policy that essentially all transactions governed by the loan contracts do not constitute federal actions, in that the purpose of the loan contracts and related security documents (for us, our first mortgage indenture) is to maintain security for repayment of debt issued under a previous agency action.

Department of Energy

    Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005, we entered into a loan guarantee agreement with the Department of Energy in 2014, pursuant to which the Department of Energy agreed to guarantee our obligations under a multi-advance term loan facility with the Federal Financing Bank.

    Proceeds of advances made under the facility will be used to reimburse us for a portion of certain costs of construction relating to two additional nuclear units at Plant Vogtle that are eligible for financing under the Title XVII Loan Guarantee Program. We may make advances under the facility until December 31, 2020 and aggregateAggregate borrowings under the facility may not exceed $3.1 billion of eligible project costs.costs, and as of December 31, 2017, we had borrowed $1.7 billion under this loan. Advances may not occur after December 31, 2020. All advances received under this facility are secured under our first mortgage indenture.

    Following the bankruptcy of Westinghouse in March 2017, the loan guarantee agreement was amended to restrict advances pending the satisfaction of certain conditions, including the Department of Energy's

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approval of the Bechtel Agreement and a further 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.

    Under this loan guarantee agreement, we may have to obtain approval from the Department of Energy or provide the Department of Energy with a notice and opportunity to object before we take certain actions, including, without limitation,

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significant dispositions of system assets, including restrictions on the transfer of our undivided ownership interest in Vogtle Units No. 3 and No. 4 prior to commercial operation of both units,



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changes to the wholesale power contracts and the formulary rate contained in the wholesale power contracts,



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certain changes to plant ownership and operating agreements relating to Vogtle Units No. 3 and No. 4, and



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agreeing to the removal or replacement of Georgia Power Company or Southern Nuclear Operating Company, Inc. in their respective roles as agents for the Co-owners in connection with the additional Vogtle units.

    In September 2017, the Department of Energy issued a conditional commitment to us for $1.6 billion of additional guaranteed funding under the loan guarantee agreement. This additional funding is subject to an amendment and restatement of the loan guarantee agreement and satisfaction of certain other conditions. The conditional commitment expires on June 30, 2018, subject to any extension approved by the Department of Energy. While not assured, we expect to close on this additional loan in the second quarter of 2018.

    AsFor additional information regarding the current status of December 31, 2015, we advanced $1.2 billion under this loan. Allthe loan guarantee agreement, including conditions to future advances made under this facility are secured under our first mortgage indenture.and potential repayment over a five-year period, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION –Financial Condition-Financing Requirements – Department of Energy –Guaranteed Loan" andNOTE 7a of Notes to Consolidated Financial Statements. For additional information on Vogtle Units No. 3 and No. 4, see "– OUR POWER SUPPLY RESOURCES –Future Power Resources –Vogtle Units No. 3 and No. 4."

Relationship with Georgia Transmission Corporation

    We and our 38 members are members of Georgia Transmission Corporation (An Electric Membership Corporation), which was formed in 1997 to own and operate the transmission business we previously owned. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. Georgia Transmission also provides transmission services to third parties. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities.

    Georgia Transmission has rights in the integrated transmission system, which consists of transmission facilities owned by Georgia Transmission, Georgia Power Company, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia. Through agreements, common access to the combined facilities that compose the integrated transmission system enables the owners to use their combined resources to make deliveries to or for their respective consumers, to provide transmission service to third parties and to make off-system purchases and sales. The integrated transmission system was established in order to obtain the benefits of a coordinated development of the parties' transmission facilities and to make it unnecessary for any party to construct duplicative facilities.

Relationship with Georgia System Operations Corporation

    We, Georgia Transmission and our 38 members are members of Georgia System Operations Corporation, which was formed in 1997 to own and operate the system operations business we previously owned. Georgia System Operations operates the system control center and currently provides Georgia Transmission and us with system operations services and administrative support services. We have contracted with Georgia System Operations to schedule and dispatch our resources. We also purchase from Georgia System

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Operations services that it purchases from Georgia Power under the control area compact,Control Area Compact, which we

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co-signed with Georgia System Operations. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES –Members' Relationship with Georgia Transmission and Georgia System Operations." Georgia System Operations provides support services to us in the areas of accounting,accounts payable, payroll, auditing, communications, human resources, facility management,campus services, telecommunications and information technology at cost.

    We currently have approximately $9.7$13.1 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $4.0 million that can be drawn under one of its loans with us.

    Georgia Transmission has contracted with Georgia System Operations to provide certain transmission system operation services including reliability monitoring, switching operations, and the real-time management of the transmission system.

Relationship with Georgia Power Company

    Our relationship with Georgia Power is a significant factor in several aspects of our business. Except for the Rocky Mountain Pumped Storage Hydroelectric Facility, Georgia Power, on behalf of itself as a co-owner and as agent for the other co-owners, is responsible for the construction and operation of all our co-owned generating facilities, including the development and construction of Vogtle Units No. 3 and No. 4. For further information regarding the agreements between Georgia Power and us, see "PROPERTIES – Fuel Supply," "– Co-Owners of Plants –Georgia Power Company" and "– The Plant Agreements." Georgia Power supplies services to us and Georgia System Operations to support the scheduling and dispatch of our resources, including off-system transactions. Georgia Power and our members are competitors in the State of Georgia for electric service to any new customer that has a choice of supplier under the Georgia Territorial Electric Service Act, which was enacted in 1973, commonly known as the Georgia Territorial Act.Act (see "– Competition"). For further information regarding the agreements between Georgia Power and us and our members' relationships with Georgia Power, see "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Service Area and Competition" and "PROPERTIES – Fuel Supply,"
"– Co-Owners of Plants –Georgia Power Company" and "– The Plant Agreements."Competition.

Relationship with 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 718728 megawatts. We provide operations, financial and management services for Smarr EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

Relationship to Green Power EMC

    Green Power Electric Membership Corporation, owned by our 38 members, is a power supply cooperative specializing in the purchase of renewable energy for its members. The members purchase small quantities of energy from Green Power EMC. We supply financial and management services to Green Power EMC. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.Resources –Green Power EMC."

Competition

    Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories. Since 1973, however, the Georgia Territorial Act has permitted limited competition among electric utilities located in Georgia for sales of electricity to certain large commercial or industrial customers. The owner of any new facility may receive electric service from the power supplier of its choice if the facility is located outside of municipal limits and has a connected load upon initial full operation of 900 kilowatts or more. Our members are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. While the competition for 900-kilowatt loads represents only limited competition in Georgia, this competition has given our members the opportunity to develop resources and strategies to operate in a more competitive market.

    Some states have implemented varying forms of retail competition among power suppliers. No legislation related to retail competition has yet been enacted in Georgia which would amend the Georgia Territorial Act or otherwise affect the exclusive right of our members to supply power to their current service territories. However, parties have unsuccessfully sought and will likely continue to seek to advance legislative proposals that will directly or indirectly affect the Georgia

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Territorial Act in order to allow increased retail competition in our members' service territories. The Georgia Public Service Commission does not have the authority under Georgia law to order retail competition or amend the Georgia Territorial Act. We cannot predict at this time the outcome of various developments that may lead to increased competition in the electric utility industry or the effect of any developments on us or our members.

    We routinely consider, along with our members, a wide array of other potential actions to meet future power supply needs, to reduce costs, to reduce risks of the competitive generation business and to respond to competition. Alternatives that could be considered include:

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construction or acquisition of power marketing arrangementssupply resources, whether owned by us or by other alliance arrangements;entities;



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adding renewable generation sources;



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adjusting the mix of ownership and purchase arrangements used to meet power supply requirements;



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construction or acquisition of power supply resources, whether owned by us or by other entities;



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use of power purchase contracts to meet power supply requirements, and whether to use short, medium or long-term contracts, or a mix of terms;



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participation in future power supply resources developed by others, whether by ownership or long-term purchase commitment;



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whether dispositionuse of existing assets or asset classes would be advisable;storage technologies;



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maturity extensions of existing indebtedness;



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potential prepayment of debt;



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whether disposition of existing assets or asset classes would be advisable;



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various responses to the proliferation of non-core services offered by electric utilities;



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power marketing arrangements or other alliance arrangements;



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mergers or other combinations with distributors or power suppliers; and



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other changes in our businesses intended to take advantage of current and anticipated trends in the electric industry.

    We will continue to consider industry trends and developments, but cannot predict the outcome or any action we or our members might take based on these industry trends and developments. These considerations necessarily would take account of and are subject to legal, regulatory and contractual considerations.

    Regulation of greenhouse gas emissions has the potential to affect energy suppliers, including us and our competitors, differently, depending not only on the relative greenhouse gas emissions from a supplier's sources, but also on the nature of the regulation. For example, the Clean Power Plan includes individual state goals for carbon dioxide emissions. OurSome of our generation sources emit greenhouse gas emissions are significant,gases, but we also have generation sources that emit no greenhouse gases. Some of our competitors use sources that emit proportionately more greenhouse gases, while the sources of some competitors emit less. Further, third-party suppliers to our members are relying on generation sources that emit greenhouse gases. The terms and conditions in the contracts with these third-party suppliers would determine the extent to which our members would be affected by regulation of the greenhouse gas emissions of these suppliers. We believe our and our members' diverse portfolios of generation facilities, including the diversity of third-party suppliers, would mitigate any impact on our and our members' competitiveness resulting from these regulations.any regulation. See "REGULATION – Environmental –Carbon Dioxide Emissions and Climate Change" and "RISK FACTORS."

    Many members are also providing or considering proposals to provide non-traditional products and services such as natural gas, telecommunications and other services. The Georgia Public Service Commission can authorize member affiliates to market natural gas but is required to condition any authorization on terms designed to ensure that cross-subsidizations do not occur between the electricity services of a member and the gas activities of its gas affiliates.

    Depending on the nature of the generation business in Georgia, there could be reasons for the members to separate their physical distribution business from their energy business, or otherwise restructure their current businesses to operate more effectively.

    Further, a member's power supply planning may include consideration of assignment of its rights and obligations under its wholesale power contract to another member or a third party. We have existing provisions for wholesale power contract assignment, as well as provisions for a member to withdraw and

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concurrently to assign its rights and obligations under its wholesale power contract. Assignments upon

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withdrawal require the assignee to have certain published credit ratings and to assume all of the withdrawing member's obligations under its wholesale power contract with us, and must be approved by our board of directors. Assignments without withdrawal are governed by the wholesale power contract and must be approved by both our board of directors and the Rural Utilities Service.

    From time to time, individual members may be approached by parties indicating an interest in purchasing their systems. A member generally must obtain our approval before it may consolidate or merge with any person or reorganize or change the form of its business organization from an electric membership corporation or sell, transfer, lease or otherwise dispose of all or substantially all of its assets to any person, whether in a single transaction or series of transactions. A member may enter into such a transaction without our approval if specified conditions are satisfied, including, but not limited to, an agreement by the transferee, satisfactory to us, to assume the obligations of the member under the wholesale power contract, and certifications of accountants as to certain specified financial requirements of the transferee. The wholesale power contracts also provide that a member may not dissolve, liquidate or otherwise wind up its affairs without our approval.

Seasonal Variations

    Our members' demand for energy is influenced by seasonal weather conditions. Historically, higher demand has occurred during summer and winter months than in spring and fall months. Even so, summer and winter demand historically has been lower when weather conditions are milder and higher when weather conditions are more extreme. A variety of factors affect our members' decisions whether to purchase their increased seasonal demand from us. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION –Results of Operations – Factors Affecting Results." While changing weather patterns, whether resulting from greenhouse gas emissions or otherwise, could, under certain circumstances, alter seasonal weather patterns, predictions of future changes in weather patterns are inherently speculative, and we can notcannot make accurate conclusions about seasonality related to changes in weather patterns. Our energy revenues recover energy costs as they are incurred and also fluctuate month to month. Capacity revenues reflect the recovery of our fixed costs, which do not vary significantly from month to month; therefore, capacity charges are billed and capacity revenues are recognized in substantially equal monthly amounts.

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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 2015,2017, we supplied approximately 48%63% of the retail energy requirements of our members.

Generating Plants

    Our fleet of generating units total 7,7857,843 megawatts of summer planning reserve capacity, including 718728 megawatts of Smarr EMC assets, which we manage. This generation portfolio includes our interests in units fueled by nuclear, coal, gas, oil and water. Georgia Power, the Municipal Electric Authority of Georgia 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 capacity and energy from a "qualifying facilities"facility" under the Public Utility Regulatory Policies Act of 1978. 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 2015,2017, our purchases from suchthis qualifying facilitiesfacility 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 119 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

    In 2008,We, Georgia Power, acting for itself and as agent for us, 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 at Plant Vogtle, Units No. 3 and Westinghouse ElectricNo. 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, LLCInc. as its agent for licensing, engineering, procurement, contract management, construction and Stone & Webster, Inc. (collectively,pre-operation services.

    In 2008, Georgia Power, acting for itself and as agent for the Contractor)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, the Contractor willWestinghouse 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, Units No. 3 and No. 4. Our ownership interest and proportionate shareVogtle. Under the terms of the cost to construct these units is 30%.

    Under the EPC Agreement, the Co-owners willagreed to pay a purchase price that is subject to certain price escalations and adjustments, including fixed escalation amounts and index-based adjustments. Toshiba Corporation guaranteed certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon the Contractor's failure to fulfill the schedule and performance guarantees, subject to a cap. In addition,payment obligations of Westinghouse under the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions. The maximum amount of additional capital costs under this provision attributable to us is $75 million. Each Co-owner is severally, not jointly, liable to the Contractor for its proportionate share, based on ownership interest, of all amounts owed under the EPC Agreement. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management.

    On December 31, 2015, Westinghouse acquired Stone & Webster, Inc. from Chicago Bridge & Iron Co. N.V. (the Acquisition). In connection with the Acquisition, Stone & Webster, Inc. changed its name toToshiba Guarantee),

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WECTEC Global Project Services Inc. (WECTEC). Certain obligationsincluding any liability of Westinghouse for abandonment of work. Until March 2017, construction on Units No. 3 and Stone & Webster, Inc. have been guaranteed by Toshiba Corporation, Westinghouse's parent company, and The Shaw Group Inc., a subsidiary of Chicago Bridge & Iron, respectively.No. 4 continued under the substantially fixed price EPC Agreement.

    On March 9, 2016, in29, 2017, Westinghouse filed for bankruptcy protection under Chapter 11 of the United States Bankruptcy Code. In connection with the Acquisitionbankruptcy filing, Georgia Power, acting for itself and pursuantas 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 on 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 described below,Amendment, Toshiba was deemed to be the guaranteeowner of The Shaw Group was terminated. The guaranteecertain pre-petition bankruptcy claims of Toshiba remains in place. Additionally, as a result of recent credit rating downgrades of Toshiba, Westinghouse has provided the Co-owners withand certain affiliates of the Municipal Electric Authority of Georgia against Westinghouse, and the Co-owners surrendered certain letters of credit securing a portion of approximately $900 million in accordanceWestinghouse'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), for Westinghouse to transition construction management of Vogtle Units No. 3 and No. 4 to Southern Nuclear and to provide ongoing design, engineering, and procurement services to Southern Nuclear. On July 20, 2017, the bankruptcy court approved Westinghouse's motion seeking authorization to (i) enter into the Services Agreement, (ii) assume and assign to the Co-owners certain project-related contracts, (iii) join the Co-owners as counterparties to certain assumed project-related contracts, and (iv) reject the EPC Agreement. The Services Agreement, and Westinghouse's rejection of the EPC Agreement, became effective upon approval by the Department of Energy on July 27, 2017. The Services Agreement 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.

    Effective 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, whereby Bechtel will serve 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 be reimbursed for actual costs plus a base fee and an at-risk fee, which is subject to adjustment based on Bechtel's performance against cost and schedule targets. Each Co-owner is severally, 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 terms of the EPCBechtel Agreement. In the event of certain credit rating downgrades of any Co-owner, such Co-owner will be required to provide a letter of credit or other credit enhancement.

The Co-owners may terminate the EPCBechtel 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 costs. The Contractortermination-related costs and, at certain stages of the work, the applicable portion of the at-risk fee. Bechtel may also terminate the EPCBechtel Agreement under certain circumstances, including, certain suspension or delaysCo-owner suspensions of work, by the Co-owners, action by a governmental authority to stop work permanently, certain breaches of the EPCBechtel 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.

    The Nuclear Regulatory Commission certifiedOn November 2, 2017, the Westinghouse AP1000 Design Control Document (DCD) in late 2011. In early 2012, the Nuclear Regulatory Commission issued combined construction and operating licensesCo-owners entered into an amendment to their joint ownership agreements for Vogtle Units No. 3 and No. 4 (as amended, the Joint Ownership Agreements) to provide for, among other conditions, additional Co-owner approval requirements. Pursuant to the Joint Ownership Agreements, the holders of at least 90% of the ownership interests in Vogtle Units No. 3 and No. 4 must vote to continue construction if certain adverse events occur, including: (i) the bankruptcy of Toshiba; (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 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.

    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 that 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 and assumptions upon which allowed fullGeorgia Power's seventeenth VCM report are based do not materialize, both Georgia Power and the Public Service Commission reserve the right to reconsider the decision to continue construction. Parties have filed two petitions with the Fulton County Superior Court appealing the Georgia 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.

    We expect Vogtle Units No. 3 and No. 4 to be placed in service by November 2021 and November 2022, respectively. Our project budget for the additional Vogtle units is $7.0 billion, which includes capital costs, allowance for funds used during construction and a contingency amount. This budget is net of the $1.1 billion of payments we received from Toshiba under the Guarantee Settlement Agreement. As of December 31, 2017, 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 begin.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.

    As construction continues, risks remain that construction-related challenges, including management of contractors, subcontractors, and vendors, labor productivity and availability, fabrication, delivery, assembly and installation of plant systems, structures and components, or other issues could further impact the projected schedule and cost. Aspects of the Westinghouse AP1000 design are based on new technologies and commercial operation of this design has yet to be tested.

    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 levels,level and additional challenges may arise as construction proceeds.

    In 2012,arise. Processes are in place that are designed to assure compliance with the Co-owners and the Contractor commenced litigation regarding the costs associated with design changes to the DCD and the delaysrequirements specified in the timing of approval of the DCDWestinghouse Design Control Document and issuance of the combined construction and operating licenses, including inspections by Southern Nuclear and the assertion byNuclear 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 Contractor thatNuclear Regulatory Commission. Various design and other licensing-based compliance matters, including the Co-owners are responsible for these costs undertimely resolution of inspections, tests, analyses, and acceptance criteria and the terms of the EPC Agreement. The Contractor also asserted that it was entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. In May 2014, the Contractor filed an amended claim alleging that (i) the design changes to the DCD imposedrelated approvals by the Nuclear Regulatory Commission, delayed module production andmay 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 impactsproject schedule that could result in increased costs to the Contractor are recoverable byCo-owners.

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

    See "RISK FACTORS" for a discussion of certain risks associated with the Contractor under the EPC Agreementlicensing, construction, financing and (ii) the changesoperation of nuclear generating units.

Other Future Power Resources

    From time to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. In June 2015, the Contractor updated its estimated damages, based ontime, we may assist our ownership interest, to an aggregate of approximately $470 million (in 2015 dollars). The case was pendingmembers in the U.S. District Court for the Southern District of Georgia (the Vogtle Construction Litigation).

    On December 31, 2015, Westinghouse and the Co-owners entered into a definitive settlement agreement (the Settlement Agreement) to resolve disputes between the Co-owners and the Contractor under the EPC Agreement, including the Vogtle Construction Litigation. Effective December 31, 2015, Georgia Power, acting for itself and as agent for the other Co-owners, and the Contractor entered into an amendment to the EPC Agreement to implement the Settlement Agreement. The Settlement Agreement and the related amendment to the EPC Agreement (i) restrict the Contractor's ability to seek further increases in the contract price by clarifying and limiting the circumstances that constitute nuclear regulatory changes in law; (ii) provide for enhanced dispute resolution procedures; (iii) revise the guaranteed substantial completion dates to match the currently estimated in-service dates of June 30, 2019 for Unit No. 3 and June 30, 2020 for Unit No. 4; (iv) provide that delay liquidated damages will now commence from the currently estimated nuclear fuel loading date for each unit, which is December 31, 2018 for Unit No. 3 and December 31, 2019 for Unit No. 4, rather than the original guaranteed substantial completion dates under the EPC Agreement; and (v) provide that we, based on our ownership interest, will pay to the Contractor and capitalize to the project cost approximately $230 million, of which we have paid (a) approximately $80 million prior to the Settlement Agreement under the dispute resolution procedures of the EPC Agreement and (b) approximately $80 million subsequent to December 31, 2015 underinvestigating potential new power supply resources, after compliance with the terms of the SettlementNew Business Model Member Agreement. In addition,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 Settlement Agreement provides41 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 resolutionpower needs of other open existing items relatingrural 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 scopeexpansion 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 2015 through 2017, and also shows the amount of their energy requirements that we supplied. From 2015 through 2017, peak demand of the projectmembers 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, the Georgia Territorial Act has allowed 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 only 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 EPC Agreement, including cyber security. Further, as partassets, 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 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, which begins October 2018, 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, 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 CORPORATION – Relationship with Georgia System Operations Corporation."

Member Power Supply Resources

Oglethorpe Power Corporation

    In 2017, we supplied approximately 63% 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. In 2017, 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 728 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 119 megawatts of low-impact hydroelectric, landfill gas, wood-waste biomass and solar facilities, 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 megawatts of solar facilities.

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 5 to 24 years.

    These other purchases include 156 megawatts from solar facilities under long-term contracts.

    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 propose such designations for Georgia later this year. Once finalized, Georgia must revise its State Implementation Plan (SIP) to demonstrate 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 SO₂ 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. We cannot predict the outcome of this 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. 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 10.9 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 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 reconsideration of the CPP rule.

    In October 2017, EPA proposed a rule to repeal the CPP, in large part on the revised interpretation that emission guidelines for affected existing sources are limited to the steps source owners and operators can take at the regulated source. In December 2017, EPA also issued an Advance Notice of Proposed Rulemaking seeking information on the steps existing sources could take that would be consistent with this revised interpretation.

    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 reconsider 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. We are unable to determine the ultimate impact 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. 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 further announced that it would cease sending CCR to all of its ash ponds in Georgia within three years. 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 million for the closure and post-closure of existing coal ash ponds. See Note 1 of Notes to Consolidated Financial Statements. In addition, preliminary estimates suggest that our capital expenditures to comply with the CCR rule and effluent limitations guidelines will be approximately $273 million for conversion to dry ash handling, landfill construction and wastewater treatment. More definitive cost estimates will 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 Acquisition: (i) WestinghouseState 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. 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 pursue a formal rulemaking to substantively re-evaluate the 2015 rule and may substantially revise that rule. 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.

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 engaged Fluor Enterprises, Inc.,been construed to expand the jurisdiction of the Nuclear Regulatory Commission to consider the environmental impact of a subsidiaryfacility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by the Nuclear Regulatory Commission. All aspects of Fluor Corporation,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 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 construction subcontractor; and (ii)licensee. In the Co-owners, Chicago Bridge & Iron, and The Shaw Group have entered into mutual releasesevent of any and all claims arising out of eventstakeover or circumstancesrelicensing to another, the original licensee is to be compensated in connectionaccordance 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.

    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 that occurredcould have a material impact on or before December 31, 2015. On January 5, 2016,our financial condition and results of operations.

    We are participating in the construction of two additional nuclear units at Plant Vogtle Construction Litigation was dismissed with prejudice.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 previously disclosedcurrent project budget for the additional Vogtle Units, which includes capital costs, allowance for funds used during construction and a contingency amount, is $5.0$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 11 of the United States Bankruptcy Code and its subsequent rejection of the substantially fixed price EPC Agreement.

    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 we 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 after payments contemplatedthe 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 Settlement Agreement.Nuclear Regulatory Commission;



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changes in labor costs 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;