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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
PART IV

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

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FORM 10-K

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

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

       Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No ý

       Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý Noo

       Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý Noo

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

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

       Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes oNoý

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

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

       Documents Incorporated by Reference: None

   

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OGLETHORPE POWER CORPORATION
2014 FORM 10-K ANNUAL REPORT

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CAUTIONARY STATEMENT REGARDING

FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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the regulation of carbon dioxide emissions such as the proposed Clean Power Plan, or other potential legislative and regulatory responses to climate change initiatives or efforts to reduce other greenhouse gas emissions;

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

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increasing debt caused by significant capital expenditures which is weakening certain of our financial metrics;

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commercial banking and financial market conditions;

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

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uncertainty as to the continued availability of funding from the Rural Utilities Service and our continued eligibility to receive advances from the U.S. Department of Energy for construction of two additional nuclear units at Plant Vogtle;

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actions by credit rating agencies;

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

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

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

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

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

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

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litigation or legal and administrative proceedings and settlements;

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the credit quality and/or inability of various counterparties to meet their financial obligations to us, including failure to perform under agreements;

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our members' ability to perform their obligations to us;

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

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changes in technology available to and utilized by us, our competitors, or residential or commercial consumers in our members' service territories;

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general economic conditions;

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weather conditions and other natural phenomena;

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

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unanticipated changes in interest rates or rates of inflation;

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

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

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significant changes in critical accounting policies material to us; and

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

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PART I

ITEM 1.    BUSINESS

OGLETHORPE POWER CORPORATION

General

    We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our principal business is providing wholesale electric power to our members. As with cooperatives generally, we operate on a not-for-profit basis. We are one of the largest electric cooperatives in the United States in terms of revenues, assets, kilowatt-hour sales to members and, through our members, consumers served. We are also the second largest power supplier in the state of Georgia. We have 265 employees.

    Our members are local consumer-owned distribution cooperatives that provide retail electric service on a not-for-profit basis. In general, our members' customer base consists of residential, commercial and industrial consumers within specific geographic areas. Our members serve approximately 1.8 million electric consumers (meters) representing approximately 4.2 million people. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES."

    Our mailing address is 2100 East Exchange Place, Tucker, Georgia 30084-5336, and telephone number is (770) 270-7600. We maintain a website at www.opc.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports are made available on this website as soon as reasonably practicable after this material is filed with the Securities and Exchange Commission. Information contained on our website is not incorporated by reference into and should not be considered to be part of this annual report on Form 10-K.

Cooperative Principles

    Cooperatives like Oglethorpe are business organizations owned by their members, which are also either their wholesale or retail customers. As not-for-profit organizations, cooperatives are intended to provide services to their members at the lowest possible cost, in part by eliminating the need to produce profits or a return on equity. Cooperatives may make sales to non-members, the effect of which is generally to reduce costs to members. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and banking.

    All cooperatives are based on similar business principles and legal foundations. Generally, an electric cooperative designs its rates to recover its cost-of-service and to collect a reasonable amount of revenues in excess of expenses, which constitutes margins. The margins increase patronage capital, which is the equity component of a cooperative's capitalization. These margins are considered capital contributions (that is, equity) from the members and are held for the accounts of the members and returned to them when the board of directors of the cooperative deems it prudent to do so. The timing and amount of any actual return of capital to the members depends on the financial goals of the cooperative and the cooperative's loan and security agreements.

Power Supply Business

    We provide wholesale electric service to our members for the majority of their aggregate power requirements primarily from our fleet of generation assets but also with power purchased from other power suppliers. We provide substantially all of this service pursuant to long-term, take-or-pay wholesale power contracts. The wholesale power contracts obligate our members jointly and severally to pay rates sufficient for us to recover all the costs of owning and operating our power supply business, including the payment of principal and interest on our indebtedness and to yield a minimum 1.10 margins for interest ratio under our first mortgage indenture. Our members satisfy all of their power requirements above their purchase obligations to us with purchases from other suppliers. See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources."

    Our fleet of generating units total 7,781 megawatts of summer planning reserve capacity, which includes 1,240 megawatts at the Smith facility, which is currently being sold off-system, and 718 megawatts of Smarr EMC assets that we manage but do not own. Our generation portfolio includes units powered by nuclear, coal, gas, oil and water. See "OUR POWER SUPPLY RESOURCES," "OUR MEMBERS AND THEIR POWER SUPPLY

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RESOURCES – Member Power Supply Resources – Smarr EMC" and "PROPERTIES – Generating Facilities."

    In 2014, two of our members, Cobb EMC and Jackson EMC, accounted for 13.6% and 10.4% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2014.

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 been sold 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 2014, we supplied energy that accounted for approximately 52% 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 at intervals that we deem appropriate but are required to do so at least once every year. We are required to revise

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our rates as necessary so that the revenues derived from our rates, 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

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distribution, (i) an event of default exists under the first mortgage indenture, (ii) our equity as of the end of the 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, 2014, our equity ratio was 9.3%.

    As of December 31, 2014, we had approximately $7.3 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-direct and guaranteed loan funds are subject to annual federal budget appropriations and thus cannot be assured. Currently, Rural Utilities Service-direct and guaranteed loan funds are subject to increased uncertainty because of budgetary and political pressures faced by Congress. 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 2016 provides for $6 billion in loans. Not less than $3 billion could be used for renewable energy, generation facilities with carbon sequestration, and peaking units affiliated with energy facilities that produce electricity from solar, wind and other intermittent sources of energy. Not more than $3 billion could be made available for environmental improvements to fossil-fueled generation that would reduce air emissions, consistent with any applicable state clean power plan. 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-direct and guaranteed 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 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, 2014, we had $2.6 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. Under the Rural Utilities Service's current regulations implementing the National Environmental Policy Act, essentially all transactions governed by the loan contracts between us or one of our members and the Rural Utilities Service expressly are deemed not to

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constitute major federal actions. As proposed, the rule changes may result 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 may result in added compliance costs or delays in connection with such transactions. The Rural Utilities Service and the other rural development agencies currently are reviewing comments from numerous stakeholders, including us, with respect to the proposed rule changes.

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 on February 20, 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 aggregate borrowings under the facility may not exceed $3.057 billion of eligible project costs.

    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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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.

    As of December 31, 2014, we advanced $875 million under this facility, including capitalized interest. All advances made under this facility are secured under our first mortgage indenture. 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 Operations services that it purchases from Georgia

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Power under the control area compact, which we 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, auditing, communications, human resources, facility management, telecommunications and information technology at cost.

    As of December 31, 2014, we had approximately $9.2 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $10.0 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. 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. 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."

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

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 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.

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    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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power marketing arrangements or other alliance arrangements;

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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 disposition of existing assets or asset classes would be advisable;

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maturity extensions of existing indebtedness;

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potential prepayment of debt;

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

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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 proposal includes individual state goals for carbon dioxide emissions and the use of "building blocks" to meet those goals. Our greenhouse gas emissions are significant, 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 rely 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 the impact, if any, on our and our members' competitiveness resulting from these proposals, if implemented. 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 concurrently to assign its rights and obligations under its wholesale power contract. Assignments upon 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.

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    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, our peak sales have occurred during the months of June through August. Even so, summer sales historically have been lower when weather conditions are milder and higher when weather conditions are more extreme. 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 not 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 2014, we supplied approximately 52% of the retail energy requirements of our members.

Generating Plants

    Our fleet of generating units total 7,781 megawatts of summer planning reserve capacity, including 718 megawatts of Smarr EMC assets, which we manage, and 1,240 megawatts at the Smith Energy Facility, which is currently used for off-system sales. 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 and Note 6 to Notes to Consolidated Financial Statements regarding the power purchase agreement with Doyle I, LLC that we account for as a capital lease. Also see "PROPERTIES – The Plant Agreements – Doyle." 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

Power Purchases

    We currently have no material power purchase agreements. We purchase small amounts of capacity and energy from "qualifying facilities" 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 2014, our purchases from such qualifying facilities 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.

Power Sales

    We sell energy generated at Smith to third parties when profitable. We intend to continue marketing this generation to third parties prior to our members' use of the resource, planned for 2016.

    Pursuant to a purchase and sale agreement acquired in connection with the Hawk Road Energy Facility, we sell 500 megawatts of capacity and associated energy from Hawk Road to seven of our members through December 31, 2015. After the expiration of this agreement, Hawk Road will be available to all of the participating members.

Other Power System Arrangements

    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, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia and the City of Dalton (collectively, the Co-owners) and Westinghouse Electric Company, LLC and Stone & Webster, Inc. (collectively, the Contractor) entered into an Engineering, Procurement and Construction Agreement (the EPC Agreement). Pursuant to the EPC Agreement, the Contractor will 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. Under the EPC Agreement, the Co-owners will pay a purchase price that is subject to certain price escalation and adjustments, including fixed escalation amounts and certain index-based adjustments, as well as adjustments for change orders and performance bonuses. The EPC Agreement also provides for liquidated damages upon

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the Contractor's failure to comply with schedule and performance guarantees. The Contractor's liability for those liquidated damages and for warranty claims is subject to a cap. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions which have not occurred, with maximum exposure to us of $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. Our ownership interest and proportionate share of the cost to construct Vogtle Units No. 3 and No. 4 is 30%.

    The obligations of Westinghouse and Stone & Webster are guaranteed by their parent companies Toshiba Corporation and The Shaw Group, Inc., a subsidiary of Chicago Bridge & Iron Co. N.V., respectively. In the event that any Co-owner's credit rating is downgraded below investment grade, that Co-owner would be required to provide a letter of credit or other credit enhancement to the Contractor. In addition, the Co-owners may terminate the EPC Agreement at any time for their convenience, provided that the Co-owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Contractor. The Contractor may also terminate the EPC Agreement under certain circumstances, including certain suspension or delays of work by the Co-owners, action by a governmental authority to stop work permanently, certain breaches of the EPC Agreement by the Co-owners, Co-owner insolvency and certain other events. As agent for the Co-owners, Georgia Power has designated Southern Nuclear Operating Company as its agent for contract management.

    The Nuclear Regulatory Commission certified the Westinghouse AP1000 Design Control Document (DCD) effective December 30, 2011. On February 10, 2012, the Nuclear Regulatory Commission issued combined licenses for Vogtle Units No. 3 and No. 4 which allowed full construction to begin. 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, and additional challenges may arise as construction proceeds.

    The Co-owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

    In July 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the DCD and delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses by the Nuclear Regulatory Commission, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In March 2015, the U.S. Court of Appeals for the District of Columbia affirmed the dismissal, which means the case will be tried in the U.S. District Court for the Southern District of Georgia. The portion of the additional costs claimed by the Contractor that would be attributable to us, based on our ownership interest, is approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. The Contractor did not specify amounts

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relating to these new allegations in its amended counterclaim; however, the Contractor has subsequently asserted related minimum damages, based on our ownership interest, of approximately $75 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power and the Co-owners intend to vigorously defend their positions. Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions.

    In January 2015, the Contractor notified the Co-owners, through Georgia Power, of the Contractor's proposed revised integrated project schedule for completion of Vogtle Units No. 3 and No. 4 which would delay the estimated in-service dates to the second quarter of 2019 and the second quarter of 2020, respectively. This represents an 18-month delay for each unit from the previously disclosed schedule which projected in-service dates for Vogtle Units No. 3 and No. 4 in the fourth quarter of 2017 and the fourth quarter of 2018, respectively. Georgia Power, on behalf of the Co-owners, has not agreed to any changes to the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively, and does not believe that the Contractor's proposed revision to the schedule reflects all efforts that may be possible to mitigate the Contractor's delay.

    In addition, we and Georgia Power believe that, pursuant to the EPC Agreement, the Contractor is responsible for the Contractor's costs related to the Contractor's delay (including any related construction and mitigation costs, which could be significant) and that the Co-owners are entitled to recover liquidated damages for the Contractor's delay beyond the guaranteed substantial completion dates of April 2016 and April 2017. Consistent with the Contractor's position in the pending litigation described above, we and Georgia Power expect the Contractor to contest any claims for liquidated damages and to assert that the Co-owners are responsible for additional costs related to the Contractor's delay.

    During the extended construction period, we will continue to incur our share of owner-related costs, including property taxes, oversight costs, compliance costs, and other operational readiness costs and will also continue to incur financing costs. Although Georgia Power, on behalf of the Co-owners, has not accepted the revised schedule, we expect that each additional month delay beyond the previously disclosed in-service dates for Vogtle Units No. 3 and No. 4 of the fourth quarter of 2017 and the fourth quarter of 2018, respectively, will increase our previously disclosed project budget, which includes capital costs, allowance for funds used during construction and a contingency amount, of $4.5 billion by approximately $28 million per month, which would increase our project budget to $5.0 billion should the entire eighteen-month delay be realized. We anticipate that our members will be able to utilize the generating capacity that currently exists in the region and secure sufficient amounts of economically priced energy to replace what they otherwise would have obtained from Vogtle Units No. 3 and No. 4 through the announced delay period.

    Processes are in place that are designed to assure compliance with the requirements specified in the DCD and the combined licenses, including inspections by Southern Nuclear and the Nuclear Regulatory Commission that occur throughout construction. As a result of such compliance processes, certain license amendment requests have been filed and approved or are pending before the Nuclear Regulatory Commission. Various design and other licensing-based compliance issues are expected to arise as construction proceeds, which may result in additional license amendments or require other resolution. If any license amendment requests or other licensing-based compliance issues are not resolved in a timely manner, there may be further delays in the project schedule that could result in increased costs to the Co-owners, the Contractor, or both.

    In addition, as construction continues, the risk remains that ongoing challenges with the Contractor's performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Vogtle Units No. 3 and No. 4, or other issues could arise and may further impact the project schedule and cost. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also

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likely to arise throughout construction. Any of these claims or disputes may be resolved through formal and informal dispute resolution procedures under the EPC Agreement but also may be resolved through litigation.

    The ultimate outcome of these matters cannot be determined at this time. See "RISK FACTORS" for a discussion of certain risks associated with the licensing, construction, financing and operation of nuclear generating units.

    As of December 31, 2014, our total investment in the additional Vogtle units was $2.4 billion. For information regarding our financing of Vogtle Units No. 3 and No. 4, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures" and "– Financing Activities" and Note 7 of Notes to Consolidated Financial Statements.

Other Future Power Resources

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

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OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES

Member Demand and Energy Requirements

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

    Our members serve approximately 1.8 million electric consumers (meters) representing approximately 4.2 million people. Our members serve a region covering approximately 38,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 151 of the State's 159 counties. Historically, our members' sales by customer class have been approximately two-thirds to residential consumers and slightly less than one-third to commercial and industrial consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. Each year we file with one of our quarterly reports on Form 10-Q an exhibit containing financial and statistical information for our 38 members for the most recent three year period.

    The following table shows the aggregate peak demand and energy requirements of our members for the years 2012 through 2014, and also shows the amount of their energy requirements that we supplied. From 2012 through 2014, demand requirements of the members did not increase and energy requirements increased at an average annual compound rate of 2.9%. Demand and energy requirements in 2013 were lower primarily due to milder weather.

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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 premise 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 assets, liabilities, equity, revenues or margins of our members. See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts." The assets and revenues of our members are, however, pledged under their respective mortgages with the Rural Utilities Service or loan documents with other lenders.

    We depend on the revenue we receive from our members pursuant to the wholesale power contracts to cover the costs of the 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

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Rural Utilities Service mortgage indentures of these members require them to design rates with a view to 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 that a member which 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, the availability and magnitude of Rural Utilities Service direct and guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, the availability of Rural Utilities Service loan funds is subject to increased uncertainty because of budgetary and political pressures faced by Congress.

    The President's budget proposal for fiscal year 2016 provides for loan levels of $6 billion. However, the funding is proposed to be available only for renewable energy, generation with carbon sequestration projects and certain environmental improvements. 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. In addition, potential regulatory changes by the Rural Utilities Service affecting its implementation of the National Environmental Policy Act may add to the compliance costs or delays in connection with transactions governed by the loan contracts of those members that are borrowers from the Rural Utilities Service. Because of these factors, we cannot predict the amount or cost of Rural Utilities Service direct and guaranteed 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

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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 could otherwise occur. 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 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 2014, we supplied approximately 52% of the retail energy requirements of our members. Pursuant to the wholesale power contracts, we supply each member, other than Flint, 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." We also have a power purchase and sale agreement with seven of our members for capacity and associated energy from Hawk Road through 2015. See "OUR POWER SUPPLY RESOURCES – Power Purchase and Sale Arrangements – Power Sales." 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 extend until 2016 and thereafter until terminated by two years' written notice by SEPA or the respective member. In 2014, 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, our members' SEPA power deliveries. Further, each member may be required, if certain conditions are met, to contribute funds for capital improvements for Corps of Engineers projects from which its allocation is derived in order to retain the allocation.

Smarr EMC

    The 35 members participating in the two facilities owned by Smarr EMC purchase the output of those facilities pursuant to separate take-or-pay power purchase agreements with initial terms extending through 2014 and 2015, respectively, and continuing thereafter 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 sources for its members. The members purchase small quantities of energy from Green Power EMC. We supply management services to Green Power EMC.

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-three members have entered into requirements contracts with third parties for some or all of their incremental power needs, with remaining terms ranging from 8 to 31 years. The other members use a portfolio of power purchase contracts to meet their requirements.

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

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    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 is typical for electric utilities, we are subject to various federal, state and local environmental laws that apply to our operations. 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 regulated.

    In general, these and other types of 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, oxides of nitrogen, 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 be in compliance 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 applicable to us is 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 been active regulating 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.

    National Ambient Air Quality Standards and Nonattainment Updates.    The Clean Air Act requires the EPA to set National Ambient Air Quality Standards (NAAQS) for six common air pollutants: particulate matter, ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen dioxide and lead. Many of the NAAQS have recently been revised or are in the process of being revised to be more stringent. For example, in December 2014 EPA proposed more stringent standards for the ozone NAAQS. Recently, EPA has also proposed new fine particulate matter NAAQS and is in the process of implementing the 2010 sulfur dioxide NAAQS. Although our coal-fired plants already have installed control systems for the current NAAQS, the implementation of new or revised NAAQS – like the ozone, fine particulate matter or sulfur dioxide NAAQS – could lead to additional compliance requirements. The costs of any additional pollution control equipment that could be required due to new or revised NAAQS cannot be determined at this time.

    Clean Air Interstate Rule and the Cross State Air Pollution Rule.    EPA finalized the Clean Air Interstate Rule (CAIR) in 2005 for ozone and fine particulate matter, requiring emissions reductions in sulfur dioxide and nitrogen oxides in most eastern states, including Georgia, through a market-based cap and trade program. In August 2011, EPA finalized the Cross State Air Pollution Rule (CSAPR) to replace the CAIR. Similar to and more stringent than CAIR, CSAPR imposed 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. Following extended litigation, Phase I of CSAPR began in January 2015, while Phase II of CSAPR, with its more stringent emission budgets, is scheduled to begin in January 2017. We do not anticipate the need to purchase allowances to comply with the CSAPR, given

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the completion of additional emission control systems at Plant Scherer in early 2014.

    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 – will have until April 16, 2016 to comply as one year extensions of the compliance deadline have been granted by the Georgia Environmental Protection Division. In April 2014, the U.S. Court of Appeals for the District of Columbia upheld the MATS. However, in November 2014 the U.S. Supreme Court granted several petitions for writ of certiorari on the MATS, and briefing of that appeal is now underway. We cannot predict the outcome of this litigation, but even if MATS is overturned, we would still need to comply with Georgia's mercury rules.

    Georgia's current mercury rules include a "multi-pollutant rule" that requires operation of existing controls at Plant Wansley, which include selective catalytic reduction (SCR) systems and scrubbers. To comply with MATS at Plant Wansley, modifications to allow injection of activated carbon and other chemicals have been made. At Plant Scherer, the "multi-pollutant rule" requires operation of existing controls, which include activated carbon injection equipment, baghouses, SCRs and scrubbers, and which will allow for compliance with MATS. Our total investment in all of these projects is approximately $1.1 billion.

    Startup, Shut-down or Malfunction.    On February 12, 2013, EPA proposed a rule that would require certain states to revise the provisions of their State Implementation Plans (SIPs) relating to the regulation of excess emissions at industrial facilities, including fossil fuel-fired generating facilities, during periods of startup, shut-down, or malfunction (SSM). EPA proposes a determination that the SSM provisions in the SIPs for 36 states, including Georgia, do not meet the requirements of the Clean Air Act and must be revised within 18 months of the date on which the EPA publishes the final rule. In September 2014, EPA proposed changes to its February 2013 action, proposing that all affirmative defense provisions must be removed from SIPs for compliance. Currently, EPA is under court order to issue a final SSM rule by May 2015. If finalized as proposed, this new rule could result in significant additional compliance and operational costs at our power plants. We cannot predict the ultimate outcome of this rulemaking and any ensuing litigation that may occur.

    New Source Review.    In November 1999, the United States Department of Justice, on behalf of EPA, filed lawsuits against Georgia Power and some of its affiliates, as well as other utilities. The lawsuits allege violations of the new source review provisions and the new source performance standards of the Clean Air Act at Plant Scherer Unit Nos. 3 and 4 as well as other facilities. We are not currently named in the lawsuits and we do not have an ownership interest in the named Plant Scherer units. However, we can give no assurance that units in which we have an interest will not be affected by this or a related lawsuit in the future. The case has remained administratively closed since the spring of 2001. The resolution of this matter is highly uncertain at this time, as is any responsibility for a share of any penalties and capital costs that might be required to remedy violations at the co-owned facilities.

    Rulemakings that began in 2009 now impose new source review requirements on greenhouse gases, such as carbon dioxide, under the Prevention of Significant Deterioration (PSD) preconstruction permitting program. The PSD program affects new generation resources as well as certain major modifications to existing resources. See "– Carbon Dioxide Emissions and Climate Change."

    Air Quality Summary.    We believe that the controls installed Plants Scherer and Wansley meet the requirements of the final rules described above. However, depending on the outcome of these or other rules relating to air quality, including the results of any litigation and the implementation approach selected by EPA and the State of Georgia, significant capital expenditures and increased operating expenses could be incurred at certain of our generating facilities, particularly Plants Scherer and Wansley.

Carbon Dioxide Emissions and Climate Change

    Efforts to limit emissions of carbon dioxide from power plants continue and in June 2014, the EPA

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proposed its Clean Power Plan as part of a broader effort to reduce greenhouse gas emissions.

    Emissions of carbon dioxide from our plants totaled approximately 11.1 million short tons in 2014. In 2014, 31% of our generation, excluding pumped storage, came from our interests in the coal-fired units at Plants Scherer and Wansley, which would be the most impacted by the proposed Clean Power Plan, while another 24% came from our gas-fired facilities which would also be somewhat impacted (although not to the same extent as the coal-fired plants). The remaining generation (45%) came from our interests in the nuclear Plants Vogtle and Hatch, which would likely not be directly impacted by the proposed Clean Power Plan.

    Executive Branch Action.    President Obama continues to highlight reducing greenhouse gas emissions as one of the priorities for his Administration, and any changes in requirements will most likely be the result of executive branch actions. 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, if EPA concludes regulation is needed to protect public health or welfare. EPA determined that regulation was needed and beginning in 2009 issued a series of rules that apply the Clean Air Act PSD and Title V programs to stationary source emissions of greenhouse gases.

    In June 2014, as part of President Obama's Climate Action Plan, EPA proposed two sets of New Source Performance Standards (NSPS) for: (1) new; and (2) modified and reconstructed fossil-fuel-fired electric generating units. In addition, in June 2014, EPA proposed a rule for state guidelines to establish NSPS for existing fossil fuel-fired electric generating units called the "Clean Power Plan." As proposed, the rule would cut carbon dioxide emissions from existing fossil fuel fired power plants nationwide by an average of 30% from 2005 levels by 2030, with an interim goal for 2020-2029 that would, for many states force the bulk of these reductions to be achieved prior to 2020. For Georgia, the proposal would require a 48% reduction in emission rates from 2012 levels by 2030, with 83% of that reduction slated to occur by 2020. Under the proposal, each state's carbon dioxide emissions reductions are tied to stringent state goals, determined through the application of certain "building blocks" that include efficiency upgrades, shifting generation from coal plants to natural gas facilities, expansions in renewable and nuclear power sources and implementation of demand-side energy efficiency programs. While these state goals are rate-based targets, states can convert the targets to mass-based caps and under the proposal are allowed to adopt statewide (or multi-state) cap-and-trade programs to implement such caps. EPA is scheduled to finalize the Clean Power Plan rule during the summer of 2015, and states will have until the summer of 2016 to submit their plans implementing this rule and its guidelines (plan submissions are under certain circumstances subject to extension). If finalized as proposed, the rule could result in reduced operations at our coal units, increased operation at our gas units, new renewable energy projects or purchases and energy efficiency measures by our Members. Our preliminary analysis, which incorporates both the power supply that our members receive from us as well as from other sources, indicates that the median aggregate costs to our members for a representative compliance scenario would be approximately $10 billion over the fifteen year period from 2020-2034; however, certain scenarios indicate that aggregate compliance costs could reach $20 billion for that same period, particularly if renewable energy or energy efficiency measures are mandated as part of the approach required and state emission rate targets require significant reductions in carbon intensity and significant reductions in operations at our coal plants. We anticipate that some of the policy approaches being proposed could have significant negative consequences for the economy and electric system in Georgia and the nation. However, the outcome of the Clean Power Plan, including any subsequent challenges, cannot be determined at this time and will depend on numerous factors.

    Legislation.    Based on what we know at the present time, we do not anticipate that the first session of the 114^th Congress will pass any legislation directly regulating greenhouse gases, such as carbon dioxide. We also do not anticipate the passage of any indirect standard for carbon dioxide, such as a national renewable or clean energy electricity standard. However, we cannot be certain whether any legislation will be passed by this or a future Congress that would directly or indirectly regulate greenhouse gas emissions from our power plants, nor can we predict the impacts from any such legislation.

    Litigation.    While litigation related to carbon dioxide emissions continues on numerous fronts, we cannot

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predict the outcome of such litigation, or the effect it could have on any of the power plants that we own.

    Carbon Dioxide Emissions and Climate Change Summary.    While the outcome of these matters cannot be determined at this time, adverse results in one or more of the above-described matters could result in operational restrictions and compliance costs at our fossil-fuel fired power plants, especially Plants Scherer and Wansley, which could be significant.

Coal Combustion Residuals

    In December of 2014, EPA issued a final coal combustion residuals (CCR) rule, in which it decided to regulate CCRs as non-hazardous material under Subtitle D of the Resource Conservation and Recovery Act (RCRA). The final 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. The rule is scheduled to take effect in October 2015. We are still reviewing the effects of the CCR, but they could include actions to address some or all of the requirements listed above. Significant operational changes for existing CCR storage units, extended plant outages, construction of lined landfills and groundwater monitoring facilities and additional material management and financial assurance requirements may be needed. Preliminary estimates suggest that our capital costs for compliance with the CCR (in combination with the proposed effluent limitations guidelines rule described below) could be approximately $200 million. More definitive cost estimates will be developed as the process of rule evaluation, compliance approach design and construction implementation proceeds, and the ultimate impacts associated with the CCR rule cannot be determined with certainty at this time.

Water Use and Wastewater Issues

    Since 2005, EPA has been reviewing wastewater discharges from large steam electric power plants to determine whether new Steam Electric Power Generating effluent guidelines that cover wastewater discharge standards under the Clean Water Act are needed. In 2013, EPA proposed a rule that would tighten the controls on discharges from nuclear and fossil fuel-fired steam electric power plants, by revising the effluent limitations guidelines and standards that apply to their wastewater discharges to surface waters and publicly-owned treatment works. The main pollutants EPA addresses in the proposal include metals (mercury, selenium and arsenic), nitrogen and total dissolved solids. The proposed rules could lead to more stringent standards for our power plants, especially our coal-fired facilities. EPA has stated its intent to harmonize the requirements of this rule with the final CCR rule. As discussed above, preliminary estimates suggest that our compliance cost for the revised effluent water guidelines when combined with the CCR Rule could be approximately $200 million. EPA is under a 2014 court-approved settlement to finalize the guidelines by September 2015. The ultimate impact of these guidelines cannot be determined at this time and will depend on the final regulations and any ensuing litigation.

    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. Pursuant to the State Water Plan, Georgia will consider the information contained in regional water plans when making water use permitting decisions under existing state law. Regional water plans are currently under review and are to be updated in 2016. In addition, the state water planning process may lead to new or revised regulations for water users in the future. Because power generation is generally dependent on water usage, the regional water plans and any future regulations or other enforceable requirements developed in connection with the State Water Plan may have substantial effects on the operations of our facilities or future facilities that we construct or acquire. The impacts of future regulations or revisions to regional water plans on our facilities or future facilities cannot be determined at this time.

    Section 316(b) of the Clean Water Act requires that the location, design, construction and capacity of cooling water intake structures reflect the best technology available for minimizing adverse environmental impacts on fish and other aquatic life. EPA's final section 316(b) requirements for existing

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power plants and manufacturing facilities became effective October 14, 2014. The final rule applies to all existing facilities that withdraw at least two million gallons of water per day and that use at least 25% of such water exclusively for cooling purposes. We are in the process now of conferring with the Georgia Environmental Protection Division to determine what modifications, if any, need to be made to our four co-owned power plants that trigger the cooling water use threshold (Plants Scherer, Wansley, Vogtle and Hatch) to meet the new finalized standards. Capital requirements for any additional controls that might be needed for compliance at any of these plants cannot be determined at this time, but are not expected to be significant, and the result of any litigation which has been brought challenging the final rules cannot be predicted.

    Also, on April 21, 2014, the EPA and the U.S. Army Corps of Engineers jointly published a proposed rule to revise the regulatory definition of waters of the U.S. for all Clean Water Act (CWA) programs, significantly expanding the scope of federal jurisdiction under the CWA. If finalized as proposed, this rule could significantly increase permitting and regulatory requirements and costs associated with the siting of new or modification to existing generation facilities. The ultimate impact of the rule will depend on the specific requirements of the final rule and the outcome of any legal challenges and cannot be determined 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 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. 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.

Nuclear Regulation

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

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

    In 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. The events in Japan have created uncertainties that may affect future costs for operating nuclear plants. Specifically, the Nuclear Regulatory Commission is performing additional operational and safety reviews of

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nuclear facilities in the U.S., which could potentially impact future operations and capital requirements. In addition, the Nuclear Regulatory Commission has issued a series of orders requiring safety-related changes to U.S. nuclear facilities and expects to issue orders in the future requiring additional upgrades. Estimates indicate that our increased capital and operational costs as a result of three 2012 orders and a request for information will be approximately $40 to $45 million through 2017. However, the final form and impact of additional Fukushima related changes to safety requirements for nuclear reactors will be dependent on further review and action by the Nuclear Regulatory Commission. See "RISK FACTORS" for a discussion of certain risks associated with the licensing, construction, and operation of nuclear generating units, including potential impacts that could result from a major incident at a nuclear facility anywhere in the world.

    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, as of 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.

    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 2027. See "PROPERTIES – Generating Facilities" for additional information.

    Upon or after the expiration of the license, the United States Government, by act of Congress, may take over the project, or the Federal Energy Regulatory Commission may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken. 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

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required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued.

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, generator operator and participant in wholesale power transactions, 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 make annual self-certifications of compliance with specific requirements. SERC Reliability Corporation also regularly audits 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.

We are exposed to continued schedule and cost uncertainty in connection with the construction of two additional nuclear units at Plant Vogtle.

    We have committed significant capital expenditures to participate in the construction of two additional nuclear units at Plant Vogtle. The construction of large, complex generating plants involves significant financial risk. Further, no nuclear plants have been constructed in the United States using advanced designs, such as the Westinghouse AP1000, and therefore estimating the total cost of construction and the related schedule is inherently uncertain. We also rely on 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.

    Factors that have either affected construction to date or that could lead to further cost increases and schedule delays or even the inability to complete this project include:

•

Contractor performance, including compliance with the design specifications approved and quality standards set forth by the Nuclear Regulatory Commission and continued challenges in the fabrication, assembly, delivery and installation of structural modules;

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contract disputes;

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

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failure to construct in accordance with licensing requirements;

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unforeseen engineering problems;

•

changes in project design or scope;

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work stoppages;

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permits, approvals and other regulatory matters;

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

•

erosion of public and policymaker support;

•

adverse weather conditions;

•

environmental and geological conditions;

•

unanticipated increases in the costs of materials and labor; and

•

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

    During the course of development and construction of Vogtle Units No. 3 and No. 4, certain of these factors have materialized and impacted our project budget and the originally scheduled in-service dates of April 2016 and April 2017, respectively. Most recently, in January 2015, the Contractor notified the Co-owners of its proposed revised integrated project schedule for completion of Vogtle Units No. 3 and No. 4 which would delay the estimated in-service dates to the second quarter of 2019 and the second quarter of 2020, respectively, an 18-month delay for each unit from the previously disclosed schedule. Georgia Power, on behalf of the Co-owners, has not agreed to any changes to the guaranteed substantial completion dates; however, we estimate that each month of delay increases our project-related costs by approximately $28 million. Should the most recent delay last for 18 months, our project budget would increase from $4.5 billion to $5.0 billion.

    We and the other Co-owners are also engaged in litigation with the Contractor regarding the cost responsibility for certain project-related delays. The Contractor's initial claims related to costs associated with delays related to the timing of the Nuclear Regulatory Commission issuing the necessary design and licensing approvals and the portion of those additional costs claimed by the Contractor that would be attributable to us, based on our ownership interest, is $280 million in 2008 dollars. The Contractor subsequently amended its complaint to assert that the Co-owners are responsible for the costs associated with additional construction delays and has asserted related minimum damages of approximately $75 million, based on our ownership interest. The Contractor may also from time to time continue to assert that it is entitled to additional payments with respect to these new

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allegations, any of which could be substantial. In addition, there have been technical and procedural challenges to the construction and licensing of these units and additional challenges at the federal and state level may arise as construction proceeds.

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

Our costs of compliance with environmental laws and regulations are significant and have increased in recent years. New environmental regulations, including those designed to address coal combustion residuals, will increase our compliance costs, and potential future environmental laws and regulations, including those designed to address carbon dioxide emissions, air and water quality, and other matters may result in operational restrictions or significant increases in compliance costs or liabilities.

    As with most electric utilities, we are subject to extensive federal, state and local environmental requirements which regulate, among other things, air emissions, water discharges and the use and management of hazardous and solid wastes. Compliance with these requirements requires significant expenditures for the installation, maintenance and operation of pollution control equipment, monitoring systems and other equipment or facilities.

    Generally, existing environmental regulations are becoming increasingly stringent, while new legislation or regulations, including those relating to proposed standards for carbon dioxide emissions or renewable or clean energy may create new requirements or operational hurdles. Through 2014, we have spent approximately $1.1 billion on capital expenditures at our facilities to achieve and maintain compliance with Georgia's "multi-pollutant rule" and EPA's Mercury and Air Toxics Standards (MATS), two air quality control regulations that have had a significant impact on our business to date. More stringent or new standards will likely require us to modify the design or operation of existing facilities, and could result in significant increases in the cost of electricity or decreases in the amount of energy (due to operational constraints) provided to our members, a few examples of which are discussed below.

    In June 2014, as part of President Obama's Climate Action Plan, EPA proposed a rule for new source performance standards at certain existing power plants called the "Clean Power Plan." As proposed, the rule would cut carbon dioxide emissions from existing fossil fuel fired power plants nationwide by an average of 30% from 2005 levels by 2030, with an interim goal for 2020-2029 that would, for many states force the bulk of these reductions to be achieved prior to 2020. For Georgia, the proposal would require a 48% reduction in emission rates from 2012 levels by 2030, with 83% of that reduction slated to occur by 2020, through a combination of measures that may include reduced operations at our coal units, cessation of operations at some of those coal units and new renewable energy or energy efficiency measures. EPA is scheduled to finalize the Clean Power Plan, including state-specific emission rate goals for carbon dioxide emissions by summer 2015. Our preliminary analysis, which incorporates both the power supply that our members receive from us as well as from other sources, indicates that the median aggregate costs to our members for a representative compliance scenario would be approximately $10 billion over the fifteen year period from 2020-2034; however, certain scenarios indicate that aggregate compliance costs could reach $20 billion for that same period, particularly if renewable energy or energy efficiency measures are mandated as part of the approach required and state emission rate targets require significant reductions in carbon intensity and significant reductions in operations at our coal plants. We anticipate that some of the policy approaches being proposed could have significant negative consequences for the economy and electric system in Georgia and the nation. However, the outcome of the Clean Power Plan, including any subsequent challenges, cannot be determined at this time and will depend on numerous factors.

    In December 2014, EPA adopted a final rule to regulate coal combustion residuals from electric utilities as solid wastes. We are still reviewing the ultimate effect of the adoption of this rule on our facilities and whether it will require closure or significant operational changes for existing ash ponds and other storage units, extended plant outages, construction of lined landfills, groundwater monitoring facilities and additional material management and financial assurance requirements. The EPA has also proposed a rule that would revise the effluent limitations guidelines and standards that apply to certain wastewater discharges

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from nuclear and fossil fuel-fired steam electric power plants. Preliminary estimates suggest that our capital costs for compliance with these rules could be approximately $200 million.

    Litigation relating to environmental issues, including claims of property damage or personal injury caused by plant emissions, wastewater discharges or solid waste disposal, including coal combustion residuals, is generally increasing throughout the U.S. Likewise, actions by private citizen groups to enforce environmental laws and regulations are becoming increasingly prevalent.

    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. For additional information regarding certain environmental regulations to which our business is subject, see "BUSINESS – REGULATION – Environmental."

Our capital expenditures, particularly in relation to the additional units under construction at Plant Vogtle, are projected to be significant and will continue to increase our debt.

    In order to meet the future energy needs of our members, we are participating in the construction of Vogtle Units No. 3 and No. 4. Our total estimated cost for the Vogtle project is $5.0 billion and as of December 31, 2014 our investment was $2.4 billion. As we have financed generation assets in the past, we are relying on external funding to finance this project. As of December 31, 2014, we had $7.3 billion of debt outstanding, including capital leases. At the completion of the Vogtle expansion, we expect that we will have approximately $9.7 billion of debt and capital leases outstanding.

    In addition to the increase in absolute dollars, our debt is increasing as a percentage of our total capitalization, which is weakening certain of our financial metrics. Beginning in 2009, in order to increase financial coverage during a period of generation expansion, our board of directors approved budgets to achieve a greater margins for interest ratio than the minimum 1.10 margins for interest ratio required under our first mortgage indenture. We achieved the board-approved margins for interest ratio each year, and for 2015 our board of directors approved a margins for interest ratio of 1.14. However, even with increased margins, the amount of incremental debt associated with these capital investments will continue to constrain our equity ratio during this period of increased borrowing, which could impact our credit ratings. Any downgrade in our credit ratings could increase our borrowing costs and decrease our access to the credit and capital markets.

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

    We rely on access to external funding sources as a significant source of liquidity for capital expenditure requirements not satisfied by cash flow generated from operations. Unlike most investor-owned utilities, electric cooperatives cannot issue equity securities and therefore rely almost entirely on debt financing. Historically, we and other electric generating cooperatives have relied on federal loan programs guaranteed by the Rural Utilities Service, a branch of the U.S. Department of Agriculture, in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of Rural Utilities Service funding levels are subject to the annual federal budget appropriations process, and therefore are subject to uncertainty because of budgetary and political pressures faced by Congress. Although Congress has historically rejected proposals to curtail the Rural

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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 of Rural Utilities Service loans that may be available to us in the future. If the amount of this funding available to us in the future is decreased or eliminated, we would seek alternative sources of debt financing in the traditional capital markets. Further, in 2014 the Rural Utilities Service proposed rule changes affecting its implementation of the National Environmental Policy Act which, as proposed, may result in the designation of certain transactions governed by the loan contract between us and the Rural Utilities Service as major federal actions and therefore may result in added compliance costs or delays in connection with such transactions.

    In connection with our share of the cost to construct the additional units at Plant Vogtle, in February 2014 we closed on a loan from the Federal Financing Bank and a related loan guarantee from the Department of Energy to fund up to $3.057 billion of eligible project costs through 2020. As of December 31, 2014, we had advanced approximately $875 million under this loan. Continued access to the committed funds under this loan requires us to meet certain conditions related to our business and the Vogtle project and also requires certain third parties related to the Vogtle project to comply with certain laws. Although we expect that these conditions will continue to be met, in the event that we are unable to draw the full amount of this loan, we expect that we would finance any amounts we are unable to advance, along with any amounts in excess of the remaining loan balance, through the capital markets which would likely be at a higher cost.

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

    Our borrowing costs are also affected by prevailing interest rates. Although we have hedged a significant portion of our exposure to rising interest rates related to the construction of Vogtle Units No. 3 and No. 4, the hedges we have in place only cover a portion of our total exposure to increased interest rates. If interest rates have increased at the time we issue fixed rate debt or reset the interest rates on our variable rate debt, our interest costs will increase to the extent these increases are not offset by any interest rate hedges and our financial condition and future results of operations could be adversely affected.

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

•

market conditions generally;

•

economic downturns or recessions;

•

instability in domestic or foreign financial markets;

•

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

•

the overall health of the energy and financial industries;

•

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

•

lender concerns regarding potential cost overruns associated with nuclear construction;

•

war or threat of war; and

•

terrorist attacks or threatened attacks on our facilities or the facilities of unrelated energy companies.

    If our ability to access capital becomes significantly constrained or more expensive for any of the reasons stated above or for any other reason, our ability to finance ongoing capital expenditures could be limited and our financial condition and future results of operations could be adversely affected.

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We own and are participating in the construction of nuclear facilities which give rise to environmental, regulatory, financial and other risks.

    We own a 30% undivided interest in Plant Hatch and Plant Vogtle, each of which is a two-unit nuclear generating facility, and which collectively account for approximately 18% of our generating capacity and 45% of our energy generated during 2014. Our ownership interests in these facilities expose us to various risks, including:

•

potential liabilities relating to harmful effects on the environment and human health resulting from the operation of these facilities and the on-site storage, handling and disposal of spent nuclear fuel;

•

significant capital expenditures relating to maintenance, operation, security and repair of these facilities, including repairs or modifications required by the Nuclear Regulatory Commission;

•

potential liabilities arising out of nuclear incidents caused by natural disasters, terrorist attacks or otherwise, including the payment of retrospective insurance premiums, whether at our own plants or the plants of other nuclear owners;

•

uncertainties with respect to the off-site storage and disposal of spent nuclear fuel in the event that on-site storage is not sufficient; and

•

risks related to the expected cost, and funding of the expected cost, of decommissioning these facilities at the end of their operational life.

    The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generating facilities. If our nuclear facilities were found to be out of compliance with applicable requirements, the Nuclear Regulatory Commission may impose fines or shut down one or more units of these facilities until compliance is achieved. Revised safety requirements issued by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities.

    A major incident at a nuclear facility anywhere in the world, such as the incident at the Fukushima Daiichi nuclear generating plant in Japan in 2011, could cause the Nuclear Regulatory Commission to limit or prohibit the operation or licensing of any domestic nuclear unit. While we have no reason to expect a serious incident at either of our nuclear plants, if an incident did occur, it could result in substantial cost to us.

    We are collecting for and maintain an internal fund and an external trust fund for the estimated cost of decommissioning our existing nuclear facilities. If the values of the investments in the funds significantly decrease or the anticipated decommissioning costs significantly increase, it is possible that decommissioning costs and liabilities could exceed the amount of these funds, and we would have to collect additional revenue from our members to pay the excess costs.

    In addition to our existing ownership of nuclear units, we are participating with the other Co-owners of Plant Vogtle in the construction of two additional nuclear units at the Plant Vogtle site. See "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4."

We could be adversely affected if we or our operating agents are unable to continue to operate our facilities in a successful manner.

    The operation of our generating facilities may be adversely impacted by various factors, including:

•

operating limitations that may be imposed by environmental or other regulatory requirements;

•

the risk of equipment and information technology failure or operator error;

•

interruptions in fuel, water or material supplies;

•

compliance with electric reliability organizations' mandatory reliability and record keeping standards, including mandatory cyber security standards;

•

attacks on critical information technology systems or cyber intrusion;

•

the ability to maintain a qualified workforce;

•

labor disputes;

•

terrorist attacks; or

•

catastrophic events such as fires, earthquakes, floods, droughts, hurricanes, explosions, pandemic health events such as influenzas or similar occurrences.

    We operate in a highly regulated industry that requires the continued operation of advanced

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information technology systems and network infrastructure. Our generation assets and information technology systems, or those of our co-owned plants, could be directly or indirectly affected by deliberate or unintentional cyber incidents. If our technology systems were to be breached or otherwise fail, we may be unable to fulfill critical business functions, including the operation of our generation assets and our ability to effectively maintain certain internal controls over financial reporting. Further, our generation assets rely on an integrated transmission system to deliver power to our members, and a disruption of this transmission system could negatively impact our ability to do so. In order to reduce the likelihood and severity of any cyber intrusion, we have comprehensive cyber security programs designed to protect and preserve the confidentiality, integrity and availability of data and systems. Despite these protections, a major cyber incident could result in significant business disruption and expenses to repair security breaches or system damage and could lead to litigation, regulatory action, including fines, and an adverse effect on our reputation.

    A severe drought could reduce the availability of water and restrict or prevent the operation of certain generating facilities. These or similar negative events could interrupt or limit electric generation or increase the cost of operating our facilities, which could have the effect of increasing the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

    Further, a significant percentage of our energy is generated at facilities that are operated by third parties. We rely on these operating agents for the continued operation of these facilities to avoid potential interruptions in service from these facilities. If our operating agents are unable to operate these facilities, the cost of electric service we provide to our members, or the cost of replacement electric service, may increase. See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Georgia Power Company" and "PROPERTIES – Co-Owners of Plants" for discussions of our relationship with Georgia Power and our co-owned facilities.

Changes in fuel prices could have an adverse effect on our cost of electric service.

    We are exposed to the risk of changing prices for fuels, including coal, natural gas and uranium. We have taken steps to manage this exposure by entering into fixed or capped price contracts for some of our coal requirements. We have also entered into natural gas swap arrangements designed to manage potential fluctuations in our power rates due to changes in the price of natural gas. The operator of our nuclear plants manages price and supply risk through use of long-term fixed or capped price contracts with multiple vendors of uranium ore mining, conversion and enrichment services. However, these arrangements do not cover all of our and our members' risk exposure to increases in the prices of fuels. Further, changes in the utilization of different generation resources may subject us to greater fuel price volatility; for example, as part of a broader effort to reduce carbon dioxide emissions, we may shift to generating more electricity at our natural gas fired facilities even though natural gas prices have historically been more volatile than other fuel sources. Therefore, increases in fuel prices could significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

We may not be able to obtain an adequate supply of fuel, which could limit our ability to operate our facilities.

    We obtain our fuel supplies, including coal, natural gas and uranium, from a number of different suppliers. Any disruptions in our fuel supplies, including disruptions due to weather, labor relations, environmental regulations, inadequate infrastructure, or other factors affecting our fuel suppliers, could result in us having insufficient levels of fuel supplies. For example, natural gas supplies can be subject to disruption due to natural disasters and similar events or may be unavailable due to significantly increased demand caused by exceptionally cold weather. Any failure to maintain an adequate inventory of fuel supplies could require us to operate other generating plants at a higher cost or require our members to purchase higher-cost energy from other sources and affect their ability to perform their contractual obligations to us.

We cannot predict the outcome of any current or future legal proceedings related to our business activities.

    From time to time we are subject to litigation from various parties, the most significant of which are described under "LEGAL PROCEEDINGS". Our business, financial condition, and results of operations may be materially affected by adverse results of certain

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litigation. Unfavorable resolution of legal proceedings in which we are involved or other future legal proceedings could require significant expenditures that could have the effect of increasing the cost of electric service we provide to our members and, as a result, affect our members' ability to perform their contractual obligations to us.

The operational life of some of our generating facilities exposes us to potential costs to continue to meet efficiency, reliability and environmental compliance standards.

    Many of our generating facilities were constructed over 30 years ago and, even if maintained in accordance with good engineering practices, may require significant capital expenditures in order to maintain efficient and reliable operation. Potential operational issues associated with the age of the plants may lead to unscheduled outages, a generating facility being out of service for a period of time, or other service-related interruptions. Further, maintaining compliance with applicable efficiency, reliability and environmental standards may require significant capital expenditures or operating reductions at certain of our facilities and we may determine to reduce or cease operations at those facilities in order to avoid such capital expenditures or to meet such standards. These expenditures and service interruptions could have the effect of increasing the cost of electric service we provide to our members and, as a result, could affect our members' ability to perform their contractual obligations to us.

We are subject to the risk that counterparties may fail to perform their contractual obligations which could adversely affect us.

    We routinely execute transactions with counterparties in the energy and financial services industries. These transactions include credit facilities, interest rate options, contracts related to the market price and supply of coal and natural gas, power sales and purchases and facility construction. Many of these transactions expose us to the risk that our counterparty may fail to perform its contractual obligations.

    For example, we have interest rate options outstanding with several counterparties to hedge our exposure to rising interest rates on approximately $861 million of expected borrowings related to the construction of Vogtle Units No. 3 and No. 4. If any of our counterparties in these transactions fails or refuses to honor its obligations, those interest rate hedges may not provide the protection we anticipated. Failure of our counterparties to perform their contractual obligations under the interest rate options or any of our other agreements could increase the cost of electric service we provide to our members.

Changes in power generation technology could result in the cost of our electric service being less competitive.

    Our business model is to provide our members with wholesale electric power at the lowest possible cost. A key element of this model is that generating power at central station power plants achieves economies of scale and produces power at a competitive cost. Distributed generation technologies currently exist or are in development, such as fuel cells, micro turbines, windmills and solar cells, that may in the future be capable of producing electric power at costs that are comparable with, or lower than, our cost of generating power. If these technologies were to develop sufficient economies of scale and be broadly adopted in our members' service territories, it could adversely affect our ability to recover the fixed costs related to and the value of our generating facilities and significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

Our ability to meet our financial obligations could be adversely affected if our members fail to perform their contractual obligations to us.

    We depend primarily on revenue from our members under the wholesale power contracts to meet our financial obligations. Our members are our owners, and we do not control their operations or financial performance.

    Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories, subject to limited exceptions. 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 which could affect our members' financial performance. Further, our members must forecast their load growth and power supply needs. If our members acquire more power supply resources than needed, whether from us or other suppliers, or fail to acquire sufficient resources, our members' rates could increase excessively and

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affect their financial performance. Also, in times of weak economic conditions, sales by our members may not be sufficient to cover costs without rate increases, and our members may not collect all amounts billed to their consumers. Although each member has financial covenants to set rates to maintain certain margin levels and our members' rates are not regulated by the Georgia Public Service Commission, pressure from their consumer members not to raise rates excessively could affect financial performance. Thus, we are exposed to the risk that one or more members could default in the performance of their obligations to us under the wholesale power contracts. Our ability to satisfy our financial obligations could be adversely affected if one or more of our members, particularly one of the larger members, defaulted on their payment obligations to us. Although the wholesale power contracts obligate non-defaulting members to pay the amount of any payment default pursuant to a pro rata step-up formula, there can be no guarantee that the non-defaulting members would be able to fulfill this obligation.

Regardless of our financial condition, investors' ability to trade our debt securities may be limited by the absence of an active trading market and there is no assurance that any trading market will develop or continue to remain active.

    Our debt securities are not listed on any national securities exchange or quoted on any automated quotation system. Although certain series of our debt securities at times have an active trading market, certain of our debt securities have no active trading market, including some of our outstanding auction rate securities that have been subject to continued failed auctions since 2008. Various dealers have made a market in certain of our debt securities. We have remarketing agreements in place for certain of our variable rate bonds and if a particular series of new debt securities is offered through underwriters, those underwriters may attempt to make a market in the debt securities. Dealers or underwriters have no obligation to make a market in any of our debt securities and may terminate any market-making activities at any time, for any reason, without notice. As a result, we cannot provide any assurance as to the liquidity of any trading market for our debt securities, the ability of holders to sell their debt securities or the price at which holders will be able to sell their debt securities.

    Even in an active trading market, future prices of our debt securities will depend on several factors, including prevailing interest rates, the then-current ratings assigned to the debt securities, the number of holders of the debt securities, the amount of our debt securities outstanding, the market for similar securities and our operating results.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

    None.

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ITEM 2.    PROPERTIES

Generating Facilities

    The following table sets forth certain information with respect to our generating facilities, all of which are in commercial operation.

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Plant Performance

    The following table sets forth certain operating performance information of each of our generating facilities:

    The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve months. Therefore, in some calendar years the units at these plants are not taken out of service for refueling, resulting in higher levels of equivalent availability and capacity factor. Due to low gas and market prices relative to the contract price of coal for Plant Wansley, it has been dispatched at lower levels in recent years.

Fuel Supply

    Coal.    Coal for Plant Wansley is purchased under term contracts and in spot market transactions. As of February 28, 2015, we had a 119-day coal supply at Plant Wansley based on continuous operation.

    Coal for Scherer Units No. 1 and No. 2 is purchased under term contracts and in spot market transactions. As of February 28, 2015, our coal stockpile at Plant Scherer contained a 50-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming.

    We separately dispatch Plant Wansley and Plant Scherer, but use Georgia Power as our agent for fuel procurement. We currently lease approximately 1,200 rail cars to transport coal to these two facilities.

    For information relating to the impact that the Clean Air Act may have on our coal-fired facilities, see "BUSINESS – REGULATION – Environmental – Air Quality."

    Nuclear Fuel.    Georgia Power, as operating agent, has the responsibility to procure nuclear fuel for Plants Hatch and Vogtle. Georgia Power has contracted with Southern Nuclear to operate these plants, including nuclear fuel procurement. Southern Nuclear has contracted with multiple suppliers for uranium ore, conversion services, enrichment services and fuel fabrication to satisfy nuclear fuel requirements. Most contracts are short to medium-term. The nuclear fuel supply and related services are expected to be adequate to satisfy current and future nuclear generation requirements.

    Natural Gas.    We purchase the natural gas, including transportation and other related services, needed to operate Doyle, Talbot, Chattahoochee, Hawk Road, Hartwell and Smith. We purchase natural gas in the spot market and under agreements at indexed prices. We have entered into hedge agreements to manage a portion of our exposure to fluctuations in the market price of natural gas. We manage exposure to such risks only with respect to members that elect to receive such services. We purchase transportation under long-term firm and short-term firm and non-firm contracts. We have also contracted with Petal Gas Storage, LLC to provide 800,000 MMBtu of firm natural gas storage services and related firm transportation. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Commodity Price Risk."

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Co-Owners of Plants

    Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 are co-owned by Georgia Power, the Municipal Electric Authority of Georgia, the City of Dalton and us, and Rocky Mountain is co-owned by Georgia Power and us. Each co-owner owns or leases undivided interests in the amounts shown in the following table, which excludes the Plant Wansley combustion turbine. We are the operating agent for Rocky Mountain. Georgia Power is the operating agent for each of the other plants.

Georgia Power Company

    Georgia Power is a wholly owned subsidiary of The Southern Company and is engaged primarily in the generation and purchase of electric energy and the transmission, distribution and sale of this energy. Georgia Power distributes and sells energy within the State of Georgia at retail in over 600 communities, including Athens, Atlanta, Augusta, Columbus, Macon, Rome and Valdosta, as well as in rural areas, and at wholesale to some of our members, the Municipal Electric Authority of Georgia and two municipalities. Georgia Power is the largest supplier of electric energy in the State of Georgia. See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Georgia Power Company." Georgia Power is subject to the informational requirements of the Exchange Act, and, in accordance therewith, files reports and other information with the SEC.

Municipal Electric Authority of Georgia

    The Municipal Electric Authority of Georgia, also known as MEAG Power, is a state-chartered, municipal joint-action agency that provides capacity and energy to its membership of 49 municipal electric utilities, including 48 cities and one county in the State of Georgia. MEAG Power has wholesale take-or-pay power sales contracts with each of its 49 participants that extend to June 2054. The participants are located in 39 of Georgia's 159 counties and collectively serve approximately 309,000 electric consumers (meters). MEAG Power is Georgia's third largest power supplier behind Georgia Power and us.

City of Dalton, Georgia

    Dalton Utilities is a combined utility that provides electric, gas, water and wastewater services to the city of Dalton, located in northwest Georgia, and some of the surrounding communities. It presently serves more than 65,000 residential, commercial and industrial electric customers.

The Plant Agreements

Plants Hatch, Wansley, Vogtle and Scherer

    Our rights and obligations with respect to Plants Hatch, Wansley, Vogtle and Scherer are contained in a number of contracts between Georgia Power and us and, in some instances, MEAG Power and the City of Dalton. We are a party to four Purchase and Ownership Participation Agreements (Ownership Agreements) under which we acquired from Georgia Power a 30% undivided interest in each of Plants Hatch, Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2 and a 30% undivided interest in those facilities at Plant Scherer intended to be used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the Scherer Common Facilities). We have also entered into four Operating Agreements (Operating Agreements) relating to the operation and maintenance of Plants Hatch, Wansley, Vogtle and Scherer, respectively. The Ownership Agreements and Operating Agreements relating to Plants Hatch and Wansley are two-party agreements between Georgia Power and us. The Ownership Agreements and Operating Agreements relating to

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Plants Vogtle and Scherer are agreements among Georgia Power, MEAG Power, the City of Dalton and us. The parties to each Ownership Agreement and Operating Agreement are referred to as "participants" with respect to each such agreement.

    In 1985, in four transactions, we sold our entire 60% undivided ownership interest in Scherer Unit No. 2 to four separate owner trusts established by institutional investors. We retained all of our rights and obligations as a participant under the Ownership and Operating Agreements relating to Scherer Unit No. 2 for the term of the leases. We have extended three of the leases to 2027 and the fourth lease to 2031. The leases provide for further lease renewal and also include fair market value purchase options at specified dates. See Note 6 of Notes to Consolidated Financial Statements. In the following discussion, references to participants "owning" a specified percentage of interests include our rights as a deemed owner with respect to our leased interests in Scherer Unit No. 2.

    The Ownership Agreements appoint Georgia Power as agent with sole authority and responsibility for, among other things, the planning, licensing, design, construction, renewal, addition, modification and disposal of Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 and the facilities used in common at Plant Scherer. Each Operating Agreement gives Georgia Power, as agent, sole authority and responsibility for the management, control, maintenance and operation of the plant to which it relates. Each Operating Agreement also provides for the use of power and energy from the plant and the sharing of the costs of the plant by the participants in accordance with their respective interests in the plant. In performing its responsibilities under the Ownership and Operating Agreements, Georgia Power is required to comply with prudent utility practices. Georgia Power's liabilities with respect to its duties under the Ownership and Operating Agreements are limited by the terms of these agreements.

    Under the Ownership Agreements, we are obligated to pay a percentage of capital costs of the respective plants, as incurred, equal to the percentage interest which we own or lease at each plant. With respect to Scherer Units No. 1 and No. 2, the participants have certain limited rights to disapprove capital budgets proposed by Georgia Power and to substitute alternative capital budgets. With respect to Plants Hatch and Vogtle, any co-owner has the right to disapprove large discretionary capital improvements.

    In 1993, the co-owners of Plants Hatch and Vogtle entered into the Amended and Restated Nuclear Managing Board Agreement, which provides for a managing board to coordinate the implementation and administration of the Plant Hatch and Plant Vogtle Ownership and Operating Agreements, provides for increased rights for the co-owners regarding certain decisions and allows Georgia Power to contract with a third party for the operation of the nuclear units. In 1997, Georgia Power designated Southern Nuclear as the operator of Plants Hatch and Vogtle, pursuant to the Nuclear Operating Agreement between Georgia Power and Southern Nuclear, which the co-owners had previously approved. In connection with the amendments to the Plant Scherer Ownership and Operating Agreements, the co-owners of Plant Scherer entered into the Plant Scherer Managing Board Agreement which provides for a managing board to coordinate the implementation and administration of the Plant Scherer Ownership and Operating Agreements and provides for increased rights for the co-owners regarding certain decisions, but does not alter Georgia Power's role as agent with respect to Plant Scherer.

    The Operating Agreements provide that we are entitled to a percentage of the net capacity and net energy output of each plant or unit equal to our percentage undivided interest owned or leased in such plant or unit. Georgia Power, as agent, schedules and dispatches Plants Hatch and Vogtle. The Plant Scherer and Wansley ownership and operating agreements allow each co-owner (i) to dispatch separately its respective ownership interest in conjunction with contracting separately for long-term coal purchases procured by Georgia Power and (ii) to procure separately long-term coal purchases. We separately dispatch our ownership share of Scherer Units No. 1 and No. 2 and of Plant Wansley.

    For Plants Hatch and Vogtle, each participant is responsible for a percentage of operating costs (as defined in the Operating Agreements) and fuel costs of each plant or unit equal to the percentage of its undivided interest which is owned or leased in such plant or unit. For Scherer Units No. 1 and No. 2 and for Plant Wansley, each party is responsible for its fuel costs and for variable operating costs in proportion to the net energy output for its ownership interest, and is responsible for a percentage of fixed operating costs

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equal to the percentage of its undivided interest which is owned or leased in such plant or unit. Georgia Power is required to furnish budgets for operating costs, fuel plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and No. 2, the participants have limited rights to disapprove such budgets proposed by Georgia Power and to substitute alternative budgets. The Ownership Agreements and Operating Agreements provide that, should a participant fail to make any payment when due, among other things, such nonpaying participant's rights to output of capacity and energy would be suspended.

    The Operating Agreements for Plant Hatch and Plant Vogtle will remain in effect with respect to each unit for so long as a Nuclear Regulatory Commission operating license exists for such unit. See "BUSINESS – REGULATION – Nuclear Regulation." The Operating Agreement for Plant Wansley will remain in effect with respect to Plant Wansley Units No. 1 and No. 2 until 2016 and 2018, respectively. The Operating Agreement for Scherer Units No. 1 and No. 2 will remain in effect with respect to Scherer Units No. 1 and No. 2 until 2022 and 2024, respectively. Upon termination of each Operating Agreement, following any extension agreed to by the parties, Georgia Power will retain such powers as are necessary in connection with the disposition of the property of the applicable plant, and the rights and obligations of the parties shall continue with respect to actions and expenses taken or incurred in connection with such disposition.

    In conjunction with the development of additional units at Plant Vogtle (see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4"), we, Georgia Power, MEAG Power and the City of Dalton entered into amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, and entered into an Ownership Agreement that governs participation in Vogtle Units No. 3 and No. 4. Pursuant to this ownership agreement, Georgia Power has designated Southern Nuclear as its agent for licensing, engineering, procurement, contract management, construction and pre-operation services.

Rocky Mountain

    The Rocky Mountain Pumped Storage Hydroelectric Ownership Participation Agreement, by and between us and Georgia Power (the Rocky Mountain Ownership Agreement), appoints us as agent with sole authority and responsibility for, among other things, the planning, licensing, design, construction, operation, maintenance and disposal of Rocky Mountain. The Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement (the Rocky Mountain Operating Agreement) gives us, as agent, sole authority and responsibility for the management, control, maintenance and operation of Rocky Mountain.

    In general, each co-owner is responsible for payment of its respective ownership share of all operating costs and pumping energy costs as well as costs incurred as a result of any separate schedule or independent dispatch. A co-owner's share of net available capacity and net energy is the same as its respective ownership interest under the Rocky Mountain Ownership Agreement. We and Georgia Power have each elected to schedule separately our respective ownership interests. The Rocky Mountain Operating Agreement will terminate in 2035. The Rocky Mountain Ownership and Operating Agreements provide that, should a co-owner fail to make any payment when due, among other things, such non-paying co-owner's rights to output of capacity and energy or to exercise any other right of a co-owner would be suspended until all amounts due, with interest, had been paid. The capacity and energy of a non-paying co-owner may be purchased by a paying co-owner or sold to a third party.

Doyle

    We have an agreement with Doyle I LLC, a limited liability company owned by one of our members, Walton EMC, to purchase the output of a gas-fired combustion turbine generating facility through August 24, 2015.

    During the term of the agreement, we have the right and obligation to purchase all of the capacity and energy from the facility. We are obligated to pay to Doyle I, LLC each month a capacity charge based on a performance rating and an energy charge equal to all costs of operating the facility. We are also obligated to pay the actual operation and maintenance costs and the costs of capital improvements. We are responsible for supplying all natural gas necessary to operate the facility. We have the right to dispatch the facility.

    Doyle I, LLC operates the facility. Doyle I, LLC must make the units available from May 15 to September 15 each year. Subject to air permit and other

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limitations, we may dispatch the facility at other times to the extent that the facility is available.

    We have exercised our option to purchase the facility and expect the acquisition to close on August 24, 2015. We currently account for this agreement as a capital lease of the facility for financial reporting purposes (see Note 6 of Notes to Consolidated Financial Statements).

ITEM 3.    LEGAL PROCEEDINGS

    The ultimate outcome of pending litigation against us cannot be predicted at this time; however, we do not anticipate that the ultimate liabilities, if any, arising from such proceedings would have a material effect on our financial condition or results of operations.

Vogtle Units No. 3 and No. 4

    See "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4" for a discussion of legal proceedings related to our participation in the construction of two additional units at Plant Vogtle.

Patronage Capital Litigation

    On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. See "BUSINESS – OGLETHORPE POWER CORPORATION – First Mortgage Indenture.". Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

    On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

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    We intend to defend vigorously against all claims in the above-described litigation.

    For information about loss contingencies that could have an effect on us, see Note 12 of Notes to Consolidated Financial Statements.

ITEM 4.    MINE SAFETY DISCLOSURES

    Not Applicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

    Not applicable.

ITEM 6.    SELECTED FINANCIAL DATA

    The following table presents our selected historical financial data. The financial data presented as of the end of and for each year in the five-year period ended December 31, 2014, has been derived from our audited financial statements. This data should be read in conjunction with "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and the "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."

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ITEM 7.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Executive Overview

General

    Our principal business is reliably providing wholesale electric service to our 38 members in a safe and cost effective manner. Consequently, our revenues and cash flow are primarily derived from sales to our members pursuant to take-or-pay wholesale power contracts that extend through 2050. These contracts obligate our members jointly and severally to pay all of our costs and expenses associated with owning and operating our power supply business. To that end, our rate structure provides for a pass-through of actual energy costs. Charges for fixed costs, including capacity, other non-energy charges, debt service obligations and the margin required to meet our budgeted margins for interest ratio are carefully managed throughout the year to ensure that we collect sufficient capacity-related revenues. Our rate structure provides us with the ability to manage our revenues to assure full recovery of our costs and has enabled us consistently to meet our financial obligations since our formation in 1974.

2014 Financial Results

    We remain well positioned, both financially and operationally, to fulfill our obligations to our members, bondholders and creditors. Our revenues in 2014 were more than sufficient to recover all of our costs and to satisfy all of our debt service obligations and financial covenants. Specifically, we recorded a net margin of $46.6 million in 2014, which achieved the 1.14 margins for interest ratio approved by our board of directors and exceeded the 1.10 margins for interest ratio required to meet the rate covenant under our first mortgage indenture.

    Since 2009, we targeted higher margins than necessary to meet our margins for interest ratio covenant of 1.10. We believe this was prudent due to significant capital expenditures and increased debt to fund those capital expenditures. We have achieved our targeted margins each year since 2009 and, as a result, our patronage capital increased significantly, from $536 million at December 31, 2008 to $761 million at December 31, 2014. For 2015, we are again targeting a margins for interest ratio of 1.14, effectively increasing our annual margins by 40% over the minimum required level. We anticipate that we will continue to target a 1.14 margins for interest ratio target through the completion of Vogtle Units No. 3 and No. 4 construction.

    In connection with expanding our generation capacity and upgrading our generation facilities, our total assets have increased to $9.5 billion at December 31, 2014 from $5.0 billion at December 31, 2008, and our total debt, including capital leases, has increased to $7.4 billion from $3.6 billion during the same period. As we continue to construct Vogtle Units No. 3 and No. 4 and upgrade our other facilities, our assets, debt, and equity will continue to increase.

Asset Management

    One of our primary focus areas is ensuring that our owned and operated generation facilities perform in the most efficient and cost-effective manner possible. Our Operational Excellence program strives to achieve safety, reliability and compliance in a cost effective manner. Many of the generation facilities we operate rank in the top quartile of similar plants in one or more key performance indicators, including start reliability, peak season availability and forced outages. Achieving operational excellence results in the most reliable, efficient and lowest cost power supply for our members; therefore, effective asset management will continue to be one of our top priorities.

Environmental Regulations

    A key component in effective asset management is maintaining compliance with all applicable environmental regulatory standards. In general, environmental regulations are becoming increasingly stringent which is presenting challenges to us and our members. Through 2014, we had spent approximately $1.1 billion on various projects at our coal-fired facilities in order to comply with the Georgia "multi-pollutant rule" and other regulatory requirements. As an electric cooperative that operates on a not-for-profit basis, our compliance costs are ultimately borne by our members' electricity consumers.

    In June 2014, the EPA proposed its "Clean Power Plan," designed to cut carbon dioxide emissions from existing fossil-fueled power plants nationwide by an average of 30% from 2005 levels by 2030, with interim goals beginning in 2020. We believe that the rule, as

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proposed, is significantly flawed and filed comments with the EPA detailing several objections. We also believe that the proposed rule unfairly targets Georgia, by proposing a 48% reduction in emission rates from 2012 levels, and could have significant negative consequences for the economy and electric systems of Georgia and nationwide. If finalized as proposed, our preliminary analysis, which incorporates both the power supply that our members receive from us as well as from other sources, indicates that the median aggregate costs to our members for a representative compliance scenario would be approximately $10 billion over the fifteen year period from 2020-2034. However, certain scenarios indicate that the compliance costs could reach $20 billion for that same period particularly if renewable energy or energy efficiency measures are mandated as part of the approach required and state emission rate targets require significant reductions in carbon intensity and significant reductions in operations at our coal plants. Despite the potential compliance costs and operational disruption that may result from the Clean Power Plan, we believe that we can effectively manage such challenges and that our diverse asset base positions us well to continue to meet our members' needs.

    Two other environmental regulations that could have an impact on us are the recently finalized coal combustion residuals rule and the proposed effluent water regulations. Preliminary analysis of those rules indicates that our cost to comply will be approximately $200 million over the next six years.

Vogtle Units No. 3 and No. 4

    In addition to the efficient management of our existing resources, we, through our agent, Georgia Power, and the other Co-owners of Plant Vogtle have contracted with Westinghouse and Stone & Webster to construct two additional nuclear units at the Plant Vogtle site. These units will have an aggregate generating capacity of approximately 2,200 megawatts and our 30% undivided interest will entitle us to approximately 660 megawatts of carbon-free, baseload generating capacity.

    As is often the case in the construction of large, complex generation facilities, significant issues have materialized during the course of licensing and construction that have caused revisions to the original schedule and budget. Most recently, in January 2015, the Contractors notified Georgia Power, on behalf of the Co-owners, of a revised integrated project schedule that provides for commercial operation dates for Vogtle Units No. 3 and No. 4 in the second quarter of 2019 and 2020, respectively, an 18-month delay from the prior anticipated commercial operation dates of December 2017 and December 2018. Based on this incremental delay, our estimated project budget, which includes a contingency amount, has increased from $4.5 billion to $5.0 billion.

    We and the other Co-owners are currently in litigation with the Contractor regarding the cost responsibility for certain project-related delays. Both in this litigation and generally, we are aggressively seeking to enforce the terms of the EPC Agreement and have not agreed to any change to the guaranteed substantial completion dates of 2016 and 2017, respectively. We also expect to seek liquidated damages for certain of the Contractor's delays.

    Although we are disappointed by the Contractor's continued performance delays, the project is now more than 50% complete and the Contractor continues to make progress on critical path activities. We, along with the other Co-owners, have an uncompromising focus on safety and quality in the construction of these units and are focused on working with the Contractor and Nuclear Regulatory Commission to ensure that this project meets the rigorous safety standards applicable to this "first of a kind" endeavor. We believe that Vogtle Units No. 3 and No. 4 will be valuable long-term assets that will play a key role in maintaining a diversified generation portfolio and reliably serving the long-term power needs of our members, and we remain firmly committed to the completion of these units.

Liquidity Position

    One of the most positive attributes contributing to our solid financial standing is our strong liquidity position. This liquidity is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and commercial paper. Our primary source of liquidity is a $1.21 billion unsecured credit facility, which also supports our commercial paper program, which we amended and renewed in March 2015 and extends through March 2020. We have another $400 million available through additional secured and unsecured credit facilities.

    We regularly analyze our liquidity program to appropriately size our credit portfolio to match our

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anticipated financial needs over the near-term. Securing $493 million of long-term financing from the Rural Utilities Service for the acquisition of Smith and closing on the $3.057 billion Department of Energy-guaranteed loan to finance a portion of the construction of Vogtle Units No. 3 and No. 4, under which we had advanced $875 million as of December 31, 2014, are two factors that prompted us to reduce our overall liquidity by approximately $400 million over the past six months through restructuring our portfolio of credit facilities. We will continue to evaluate our anticipated financial needs and will maintain a robust liquidity program based on those needs.

Outlook for 2015

    We remain focused on providing reliable, safe, and cost-effective energy to our members and the 4.2 million people they serve and believe we continue to be well positioned to do so. As part of this effort, during 2015 we will be preparing to integrate the Hawk Road and Smith Energy Facilities, an additional 1,750 megawatts of capacity, into the mix of assets that we utilize to meet our members' power supply needs beginning on January 1, 2016. As discussed above, there are certain risks and challenges that we must continue to address; however, as we manage our risks, we intend to keep doing what we have done so successfully for the last 41 years, including, among other things:

•

Maintaining a balanced diversity of generating resources – primarily nuclear, coal, natural gas and hydro and continuing the efficient and cost-effective operation of these resources;

•

Maintaining strong liquidity to fulfill current obligations and to finance future capital expenditures; and

•

Working with our members, as opportunities arise, to evaluate new resources to be acquired or developed by us to help meet our members' power supply requirements.

Accounting Policies

Basis of Accounting

    We follow generally accepted accounting principles in the United States and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service.

Critical Accounting Policies

    We have determined that the following accounting policies are critical to understanding and evaluating our financial condition and results of operations and requires our management to make estimates and assumptions about matters that were uncertain at the time of the preparation of our financial statements. Changes in these estimates and assumptions by our management could materially impact our results of operations and financial condition. Our management has discussed these critical accounting policies and the related estimates and assumptions with the audit committee of our board of directors.

    Regulatory Accounting.    We are subject to the provisions of the Financial Accounting Standards Board (FASB) authoritative guidance issued regarding regulated operations. The guidance permits us to record regulatory assets and regulatory liabilities to reflect future cost recoveries or refunds, respectively, that we have a right to pass through to our members. At December 31, 2014, our regulatory assets and liabilities totaled $484.0 million and $194.1 million, respectively. While we do not currently foresee any events such as competition or other factors that would make it not probable that we will recover these costs from our members as future revenues through rates under our wholesale power contracts, if such an event were to occur, we could no longer apply the provisions of accounting for regulated operations, which would require us to eliminate all regulatory assets and liabilities that had been recognized as a charge to our statement of revenues and expenses and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, we would be required to determine any impairment to other assets, including plants, and write-down those assets, if impaired, to their fair values.

    Asset Retirement Obligations.    Accounting for asset retirement and environmental obligations requires legal obligations associated with the retirement of long-lived assets to be recognized at fair value when incurred and capitalized as part of the related long-lived asset. In the absence of quoted market prices, we estimate the fair value of our asset retirement obligations using present value techniques, in which estimates of future cash

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flows associated with retirement activities are discounted using a credit-adjusted risk-free rate. Estimating the amount and timing of future expenditures includes, among other things, making projections of when assets will be retired and ultimately decommissioned, the amount of decommissioning costs, and how costs will escalate with inflation.

    A significant portion of our asset retirement obligations relates to our share of the future cost to decommission our operating nuclear units. At December 31, 2014, our nuclear decommissioning asset retirement obligation totaled $369.0 million, which represented approximately 85% of our total asset retirement obligations. Our remaining asset retirement obligations relate to non-nuclear retirement obligations such as those related to our share of coal facilities.

    Given its significance, we consider our nuclear decommissioning liabilities critical estimates. Approximately every three years, new decommissioning studies for Plants Hatch and Vogtle are performed. These studies provide us with periodic site-specific "base year" cost studies in order to estimate the nature, cost and timing of planned decommissioning activities for the plants. These cost studies are based on relevant information available at the time they are performed; however, estimates of future cash flows for extended periods are by nature highly uncertain and may vary significantly from actual results. In addition, these estimates are dependent on subjective factors, including the selection of cost escalation rates, which we consider to be a critical assumption. Our current estimates are based upon studies that were performed in 2012 and adopted December 31, 2012. For ratemaking purposes, we record decommissioning costs over the expected service life of each unit. The impact on measurements of asset retirement obligations using different assumptions in the future may be significant.

New Accounting Pronouncements

    In May 2014, the Financial Accounting Standards Board issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 and early adoption is not permitted. We are currently evaluating the future impact of this standard to our consolidated financial position or results of operations.

Summary of Cooperative Operations

Sources of Revenues

    We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. We supply capacity and energy to our members for a portion of their energy requirements which is our primary source of revenues. We also sell capacity and energy to non-members. Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity. Energy revenues are the revenues we receive by selling electricity which we generate or purchase.

    We have assigned fixed percentage capacity cost responsibilities to our members for all of our generation and purchased power resources. Each member has contractually agreed to pay us for the electric capacity assigned to it based on its individual fixed percentage capacity cost responsibility. The net cost to our members of this capacity may be reduced to the extent we sell capacity and energy to third parties from certain resources that members are not utilizing. For example, our members do not plan to use Smith to serve their load until 2016, and we are marketing its generation to third parties until that time to reduce their net cost of this resource.

    Each member is also contractually obligated to pay us for electric energy we provide to it based on individual usage. We do not provide our members with all of their energy requirements; however, our energy sales to our members fluctuate from period to period based on several factors, including fuel costs, weather and other seasonal factors, load requirements in the service territories of our members, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

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Formulary Rate

    The rates we charge our members are designed to cover all of our costs plus a margin. This cost-plus rate structure is set forth as a formula in the rate schedule to the wholesale power contracts between us and each of our members. These contracts require us to design capacity and energy rates that generate revenues sufficient to recover all costs, including payments of principal and interest on our indebtedness, to establish and maintain reasonable margins and to meet the financial coverage requirements under the first mortgage indenture.

    The formulary rate provides for the pass through of our fixed costs to members as capacity charges and our variable costs to members as energy charges. Fixed costs are assigned to members according to their individual fixed percentage capacity cost responsibility for each resource in which they participate, and variable costs are passed through to our members as energy charges based on the amount of energy sold to each member.

    Capacity charges are based on an annual budget of fixed costs plus a targeted margin and are billed to members in equal monthly installments over the course of the year. Fixed costs include items such as depreciation, interest, fixed operations and maintenance expenses, administrative and general expenses. We monitor fixed cost budget variances to projected actual costs throughout the year, and with board approval, make budget adjustments when and as necessary to ensure that we generate revenues sufficient to recover all costs and to meet our targeted margin. Budget adjustments are typically made twice a year; once during the first quarter and again at year end. In contrast to the way we bill our members for capacity charges, which are billed based on a budget and trued up to actuals by the end of the year, energy charges are billed on more of a real-time basis. Estimated energy charges are billed to members based on the amount of energy sold to each member during the month, and are adjusted when actual costs are available, generally the following month. Energy charges, or variable costs, include fuel, purchased energy and variable operations and maintenance expenses. Each generating resource has a different variable cost profile, and members are billed based on the energy cost profile of the resources from which their energy is supplied.

Margins

    Revenues in excess of current period costs in any year are designated as net margin in our statements of revenues and expenses and we have generated a positive net margin every year since our formation in 1974. Under our first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates that 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. See "BUSINESS – OGLETHORPE POWER CORPORATION – First Mortgage Indenture" for a discussion of how we calculate our 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.

    Prior to 2009, we budgeted and achieved annual margins for interest ratios of 1.10, the minimum required by the first mortgage indenture. To enhance margin coverage during a period of increased capital requirements, our board of directors has approved budgets with margins for interest ratios that exceeded 1.10. Since 2010, we have achieved our board approved margins for interest ratio of 1.14, and our board has approved a margins for interest ratio of 1.14 for 2015. As our capital requirements continue to evolve, our board will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below 1.10.

Patronage Capital

    Retained net margins are designated on our balance sheets as patronage capital. As a cooperative, patronage capital constitutes our principal equity. As of December 31, 2014, we had $761 million in patronage capital and membership fees. Our equity ratio, calculated as patronage capital and membership fees divided by total capitalization and long-term debt due within one year, was 9.3% at December 31, 2014 and 9.1% at December 31, 2013.

    Patronage capital is allocated to each of our members on the basis of its fixed percentage capacity costs responsibilities in our generation and purchased power resources. Any distribution of patronage capital is subject to the discretion of our board of directors and

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limitations under our first mortgage indenture. See "BUSINESS – OGLETHORPE POWER CORPORATION – First Mortgage Indenture" for a discussion regarding limitations on distributions under our first mortgage indenture.

Rate Regulation

    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 "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders – Rural Utilities Service." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

Tax Status

    While we are a not-for-profit membership corporation formed under the laws of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our members for purposes of calculating our taxable income. We annually allocate income and deductions between patronage and non-patronage activities and substantially all of our income is from patronage-sourced activities, resulting in no current period income tax expense or current income tax liability. For further discussion of our taxable status, see Note 5 of Notes to Consolidated Financial Statements.

Results of Operations

Factors Affecting Results

    Certain of our recent financial and operational results were affected by significant events or trends which are summarized below and followed by a more detailed discussion.

    Our energy sales to our members fluctuate from period to period based on several factors, including weather. Due to extreme cold winter weather in Georgia in 2014, and an unusually mild summer in 2013, member demand and energy requirements, and therefore, our energy sales to our members were significantly higher in 2014 compared with 2013 and were significantly lower in 2013 compared with 2012; the higher 2014 energy sales also led to higher fuel costs and, consequently, higher operating expenses in 2014.

    Since we pass through all of our costs to members, including fuel cost, which is one of our most significant operating costs, the cost of our energy sales to our members is significantly affected by fuel prices, especially the price of natural gas, which has historically faced considerable price volatility. Consistent with the overall domestic natural gas market, our price of natural gas was slightly higher in each of 2014 and 2013 compared with the previous years, however the price of natural gas in each of these years still remains significantly lower than it has been in the recent past. The slightly increased 2013 and 2014 prices resulted in increased fuel costs and, since we pass these costs through to our members as energy charges, increased energy revenues from our members. Nevertheless, the overall trend of lower natural gas prices has led to increased natural gas-fired generation over the last several years which displaced some of our coal generation, particularly at Plant Wansley which burns higher cost Eastern coal.

    Decisions to dispatch our major power plants, which may have a significant effect on our results, are driven primarily by relative fuel prices and energy requirements of our members, but are also affected by factors such as outages for maintenance or refueling. In 2014, Plant Wansley, one of our baseload coal facilities, was dispatched to conduct extensive testing of environmental equipment placed into service in that year, while in 2013, it was in reserve shutdown for most of the year primarily due to more economical generation from natural gas-fired facilities coupled with the reduced energy requirements from our members in 2013. Our nuclear units require refueling on an 18 to 24 month cycle and these refueling outages, which typically last several weeks, resulted in fluctuations in nuclear plant availability and generation in each of the last three years. These shutdowns and outages significantly reduced generation at the affected plants, reduced kilowatt-hour sales to and energy revenues from our members during the period that the plants were not generating power.

    Another key event was our acquisition of Smith, a 1,250 megawatt, combined cycle natural-gas fired facility, in April 2011. Since we are marketing the

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output from this facility to non-members until 2016, our sales to non-members and our combined cycle natural gas-fired generation and production costs have increased since 2011.

    We have also made significant capital expenditures over the past three years, particularly for the new units at Plant Vogtle, which we have primarily financed with debt. These financings have increased our overall debt which has increased our interest expense and our allowance for debt funds used during construction. Additionally, since our margin is calculated as a percentage of our secured interest expense, our net margin has also increased. As discussed under "– Financial Condition – Capital Resources – Capital Expenditures," we expect significant capital expenditures to continue through the completion of the additional units at Plant Vogtle.

Net Margin

    Our net margin for the years ended December 31, 2014, 2013 and 2012 was $46.6 million, $41.5 million and $39.3 million, respectively. These amounts produced respective margins for interest ratios of 1.14 in 2014, 2013 and 2012. For additional information on our margin requirement, see "– Summary of Cooperative Operations – Rate Regulation."

Operating Revenues

    Sales to Members.    We generate revenues principally from the sale of electric capacity and energy. The components of member revenues were as follows:

    Capacity revenues are the revenues we receive for electric service whether or not our generation and purchased power resources are dispatched to produce electricity and are designed to recover the fixed costs associated with our business, including fixed production expenses, depreciation and amortization expenses and interest charges, plus a targeted margin.

    Energy revenues are earned by selling electricity to our members, which involves generating or purchasing electricity for our members. The increase in energy revenues in 2014 as compared to 2013 was partly due to an increase in higher cost coal-fired generation and to a change in the mix of our natural gas generation with an increase in generation from our higher cost combustion turbines facilities as well as higher prices for natural gas. Energy revenues from members were lower in 2013 compared to 2012 primarily due to lower coal and natural-gas fired generation. For a discussion of fuel costs, see "– Operating Expenses."

    The following table summarizes the kilowatt-hours (in thousands) sold to members and total revenues per kilowatt-hour during each of the past three years:

    Extreme cold weather during the winter of 2014 and somewhat warmer summer weather contributed to the increase in kilowatt-hours of generation sold to members in 2014 compared to 2013. Milder weather in 2013 compared to 2012 contributed to the decrease in kilowatt-hours of generation sold to our members. For further discussion regarding fuel costs, see "– Operating Expenses."

    The energy portion of member revenues per kilowatt-hour increased 10.3% for the year ended December 31, 2014 compared to the year ended December 31, 2013 and decreased 0.2% for the year ended December 31, 2013 compared to the year ended December 31, 2012. The higher average revenue per kilowatt-hour in 2014 compared to 2013 was primarily due to the pass-through of higher fuel costs. For further

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discussion regarding fuel costs, see "– Operating Expenses."

    Sales to Non-members.    Our sales to non-members in 2014, 2013 and 2012 consisted primarily of capacity and energy sales at Smith. The Smith acquisition in 2011 included a power purchase and sale agreement with Georgia Power that expired on May 31, 2012. The decrease in 2013 compared to 2012 was due in part to the expiration of this agreement as well as lower energy demand in 2013 that was a result of milder weather. The increase in non-member sales in 2014 as compared to 2013 was primarily due to sales of natural gas of $10.8 million during the first quarter of 2014.

Operating Expenses

    Our operating expenses increased 13.3% for the year ended December 31, 2014 compared to the year ended December 31, 2013 and decreased 8.0% for the year ended December 31, 2013 compared to the year ended December 31, 2012. The increase in 2014 compared to 2013 was primarily due to higher fuel costs, higher production expenses and higher purchased power costs. The decrease in 2013 compared to 2012 was primarily due to lower fuel costs.

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

    The increase in total fuel costs for 2014 compared to 2013 was partly due to increases in coal-fired generation at Plants Scherer and Wansley and partly due to a change in the mix of our natural gas generation with an increase from our combustion turbine facilities as well as an increase in prices for natural gas. Generation from Plant Scherer increased 9.4% in 2014 compared to 2013 due to an increase in member demand driven in part by the extreme cold winter weather in 2014. Generation at Plant Wansley increased by 373,000 megawatt-hours primarily due to extensive testing of environmental equipment placed into service in 2014 as compared to 2013 when it was in reserve shut down for most of the year. The decrease in total fuel costs for 2013 compared to 2012 was primarily due to lower generation at Plant Wansley and our natural gas-fired facilities. Plant Wansley was in reserve shutdown for most of 2013 primarily due to more economical generation from natural gas-fired facilities. Generation from our gas-fired facilities also decreased in 2013 compared to 2012 due to lower utilization of Smith, although most of our gas-fired facilities experienced a decrease in generation in 2013. The decrease in total fuel costs due to lower generation was partially offset by an increase in natural gas prices in 2013.

    The changes in total fuel costs are also impacted by the amount of realized gains and losses incurred for natural gas financial hedging contracts utilized for managing exposure to fluctuations in the market prices of natural gas. For 2014 we realized a net gain of $848,000. For 2013 and 2012 we realized net losses of $3.3 million and $8.1 million, respectively.

    Production costs increased 16.0% for the year ended December 31, 2014 compared to the year ended December 31, 2013 and decreased 0.6% for the year ended December 31, 2013 compared to the year ended December 31, 2012. The increase in production expenses in 2014 compared to 2013 resulted partly from (i) planned maintenance outage work at the Smith Energy Facility, (ii) higher operations and maintenance costs at our co-owned facilities, including higher environmental expenses at the coal-fired plants and (iii) the cost of natural gas sold to non-members of $6 million. The increase in purchased power costs for the year ended December 31, 2014 as compared to the year ended December 31, 2013 resulted primarily from an increase in kilowatt-hours acquired under our energy replacement program, which replaces power from our owned generation facilities with power purchased on the spot market at a lower price.

    The effect on net margin of Smith and Hawk Road is being deferred until 2016 at which time the amounts will be amortized over the remaining life of the plants. In implementing the deferral plans, we assumed that our members would not require energy from the plants until 2016. If any of our members subscribed to Smith elect to take energy from Smith prior to 2016, the deferral of the effect on net margin would terminate for that member and the amortization of that member's deferral would commence immediately. The increase in cost deferrals in 2014 compared to 2013 resulted primarily from planned major outage work performed in 2014. The increase in cost deferrals 2013 compared to 2012 resulted primarily from a decrease in non-member sales at Smith as discussed above.

Other Income

    The gain on termination of Rocky Mountain transactions represents the net gain resulting from the July and October 2012 early termination of five of six long-term leases. The $18.9 million net gain resulted

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from the recognition of $41.4 million of the deferred net benefit associated with the terminated leases partially offset by $22.5 million of termination costs. For further discussion regarding termination of Rocky Mountain transactions, see Note 4 of Notes to Consolidated Financial Statements.

Interest Charges

    Interest on long-term debt and capital leases increased by 9.9% for the year ended December 31, 2014 compared to the year ended December 31, 2013 and increased 2.0% for the year ended December 31, 2013 compared to the year ended December 31, 2012. The increases in 2014 and 2013 compared to the same prior year periods are primarily due to the increased debt issued to finance the construction of Vogtle Units No. 3 and No. 4.

    Allowance for debt funds used during construction increased by 6.5% for 2014 compared to 2013 and by 14.3% for 2013 compared to 2012 primarily due to capital expenditures for Plant Scherer and Vogtle Units No. 3 and No. 4. The smaller increase in 2014 as compared to 2013 resulted from environmental capital improvements at Plant Scherer being placed into service in 2013 and mid-2014.

Financial Condition

Overview

    Consistent with our budgeted margin for 2014, we achieved a 1.14 margins for interest ratio which produced a net margin of $46.6 million. This net margin increased our total patronage capital (our equity) and membership fees to $761.1 million at December 31, 2014. Our 2015 budget again targets a 1.14 margins for interest ratio.

    Our equity to total capitalization ratio increased slightly from 9.1% at December 31, 2013 to 9.3% at December 31, 2014. However, in recent years our equity to capitalization ratio has been decreasing due to the amount of new debt we have incurred in connection with the expansion of our generation fleet. During the peak years of the Plant Vogtle construction, we anticipate that our equity to capitalization ratio will continue to be constrained, even though the absolute level of margins and patronage capital is increasing.

    We had a strong liquidity position at December 31, 2014, with $1.36 billion of unrestricted available liquidity, including $237 million of cash.

    Our total assets increased to $9.5 billion at December 31, 2014 from $9.1 billion at December 31, 2013. The majority of this increase relates to an increase in total electric plant in connection with constructing the additional units at Plant Vogtle.

    We maintained adequate access to capital throughout 2014, issuing $250 million of long-term debt in the capital markets. We also utilized commercial paper to provide interim financing for the Plant Vogtle construction and for other purposes at a very low cost. The average cost of funds on the $234 million of commercial paper outstanding at December 31, 2014 was 0.28%. In addition, through the Federal Financing Bank we advanced $37 million under various RUS-guaranteed loans and $875 million, including capitalized interest, under our DOE-guaranteed loan for the new Vogtle units. See "– Financing Activities" for a discussion of the long-term financing of the new Vogtle units.

    There was a net increase in long-term debt and capital leases of $282.8 million at December 31, 2014 compared to December 31, 2013. The weighted average interest rate on the $7.4 billion of long-term debt and capital leases outstanding at December 31, 2014 was 4.55%.

    Property additions during 2014 totaled $559 million. These additions include costs related to the construction of the new Vogtle units, environmental control facilities being installed at Plants Scherer and Wansley, normal additions and replacements to existing generation facilities and purchases of nuclear fuel.

Sources of Capital and Liquidity

    Sources of Capital.    Our operations have historically provided a sizable contribution to the funding of capital requirements, such that internally generated funds have provided interim or long-term funding for nuclear fuel purchases, replacements and additions to existing generation facilities, general plant additions, and retirement of long-term debt. However, due to the significant amount of expenditures relating to the construction of the new units at Plant Vogtle, we are currently funding our capital requirements through a combination of funds generated from operations and short-term and long-term borrowings.

    We have historically obtained a substantial portion of our long-term financing from Rural Utilities Service-guaranteed loans funded by the Federal Financing Bank.

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However, Rural Utilities Service funding levels for projects we may choose to undertake are uncertain and may be limited at any point in the future due to budgetary and political pressures faced by Congress. 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.

    Additionally, in February 2014 we obtained a loan from the Federal Financing Bank that is guaranteed by the Department of Energy that will fund up to $3.057 billion of the estimated $5.0 billion cost to construct our 30% undivided interest in the two new nuclear units at Plant Vogtle. Our continued access to funds under the Department of Energy-guaranteed loan is subject to our ability to meet certain conditions related to our business and the Vogtle project and also requires certain third parties related to the Vogtle project to comply with certain laws.

    See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with Federal Lenders."

    We have also obtained a substantial portion of our long-term financing requirements from the issuance of bonds in the taxable and tax-exempt capital markets, and expect to continue to access these markets in the future. However, the types of equipment that will qualify for tax-exempt financing are fewer than in the past due to changes in tax laws and regulations.

    See "– Capital Requirements – Capital Expenditures" for more detailed information regarding our estimated capital expenditures. See "– Financing Activities" for more detailed information regarding our financing plans.

    Liquidity.    At December 31, 2014, we had $1.36 billion of unrestricted available liquidity to meet short-term cash needs and liquidity requirements, consisting of $237 million of cash and cash equivalents and $1.12 billion of unused and available committed credit arrangements.

    Net cash provided by operating activities was $355 million in 2014, and averaged $248 million per year for the three-year period 2012 through 2014.

    We continually monitor our anticipated liquidity needs to gauge the appropriate level of liquidity to maintain. In 2013 we closed on a $493 million long-term Federal Financing Bank loan that is guaranteed by the Rural Utilities Service to fund the cost of acquiring the Smith Facility, and in 2014 we closed on a $3.057 billion Federal Financing Bank loan that is guaranteed by the Department of Energy to fund approximately 70% of the cost of constructing the new Vogtle units. We subsequently undertook a review of our liquidity needs which resulted in a decision to reduce our overall liquidity portfolio by approximately $400 million. We accomplished the liquidity reduction in two steps. As a first step, we elected not to renew the $150 million unsecured credit facility led by CoBank that expired on September 30, 2014. Secondly, on March 23, 2015, we replaced our $1.265 billion credit facility led by Bank of America with a $1.21 billion credit facility led by CFC and also reduced by $210 million the total amount of bilateral credit facilities that were in place with CFC prior to the closing of this transaction. The net effect of this second step was a $265 million reduction of liquidity. Combined, these actions have reduced liquidity available under our unsecured bank credit facilities by $415 million. We will continue to monitor our liquidity program to ensure that our credit portfolio appropriately covers our anticipated financial needs.

    At March 23, 2015, we had $1.61 billion of committed credit arrangements in place and $1.03 billion available under these facilities. The four separate facilities are reflected in the table below:

    We have the flexibility to use the $1.21 billion syndicated line of credit for several purposes, including borrowing for general corporate purposes, issuing letters

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of credit and to support up to $1.0 billion of outstanding commercial paper.

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

    Under our unsecured committed lines of credit, we have the ability to issue letters of credit totaling $760 million in the aggregate, of which $509 million remained available at March 23, 2015. However, amounts related to issued letters of credit reduce the amount that would otherwise be available to draw for working capital needs. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under our committed credit facilities for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue. The majority of our outstanding letters of credit are for the purpose of providing credit enhancement on variable rate demand bonds.

    We are currently issuing commercial paper to provide interim funding for payments related to the construction of Vogtle Units No. 3 and No. 4 and for the upfront premium payments made in connection with our interest rate hedging program. For a discussion of the Plant Vogtle construction, see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources – Plant Vogtle Units No. 3 and No. 4." For a discussion of our permanent financing for Vogtle Units No. 3 and No. 4 see "– Financing Activities." For a discussion of the interest rate hedging program, see "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Interest Rate Risk."

    Between projected cash on hand and the credit arrangements currently in place, we believe we have sufficient liquidity to cover normal operations and our interim financing needs, including interim financing for the new Vogtle units until permanent funds are advanced under the DOE loan.

    Two of our line of credit facilities contain similar financial covenants that require us to maintain minimum patronage capital levels. Currently, we are required to maintain minimum patronage capital of $675 million. As of December 31, 2014, our patronage capital balance was $761 million. These agreements contain an additional covenant that limits our secured indebtedness and our unsecured indebtedness, both as defined in the credit agreements, to $12 billion and $4 billion, respectively. At December 31, 2014, we had approximately $7.4 billion of secured indebtedness outstanding and $234 million of unsecured indebtedness outstanding.

    Under a power bill prepayment program we offer, members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. We currently have 20 members participating in the program and a year-end balance of $198 million remaining to be applied against future power bills.

    In addition to unrestricted available liquidity, at December 31, 2014 we had $365 million of restricted liquidity in connection with deposits made into a Rural Utilities Service Cushion of Credit Account. Deposits into the Cushion of Credit Account are voluntary and earn a rate of interest of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service on Rural Utilities Service notes and Rural Utilities Service-guaranteed Federal Financing Bank notes. From time to time we may deposit additional funds into the Cushion of Credit Account.

    Liquidity Covenants.    At December 31, 2014, we had only one financial agreement in place containing a liquidity covenant. This covenant is in connection with the Rocky Mountain lease transaction and requires us to maintain minimum liquidity of $50 million at all times during the term of the lease. We had sufficient liquidity to meet this covenant in 2014 and expect to have sufficient liquidity to meet this covenant in 2015. For a discussion of the Rocky Mountain lease transaction, see Note 4 of Notes to Consolidated Financial Statements.

Financing Activities

    First Mortgage Indenture.    At December 31, 2014, we had $7.3 billion of outstanding debt secured equally and ratably under our first mortgage indenture, an increase of $1.1 billion from December 31, 2013. A substantial portion of this increase relates to funds advanced under the Department of Energy-guaranteed Federal Financing Bank loan covering the construction of the new Vogtle units. 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

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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.

    Rural Utilities Service-Guaranteed Loans.    We currently have three approved Rural Utilities Service-guaranteed loans, funded through the Federal Financing Bank, totaling $561 million that are in various stages of being drawn down, with $226 million remaining to be advanced. As of December 31, 2014, we had $2.6 billion of debt outstanding under various Rural Utilities Service-guaranteed loans, a decrease of $94 million from December 31, 2013.

    All of the approved Rural Utilities Service loans will be funded through the Federal Financing Bank and guaranteed by the Rural Utilities Service, and the debt will be secured ratably with all other debt under our first mortgage indenture.

    Department of Energy-Guaranteed Loan.    In February 2014, we closed on a loan facility with the Department of Energy that will fund up to $3.057 billion of the cost to construct our 30% undivided share of Vogtle Units No. 3 and No. 4. The loan is being funded by the Federal Financing Bank and is backed by a federal loan guarantee provided by the Department of Energy. At December 31, 2014, we had advanced $875 million, including capitalized interest, under this loan. At December 31, 2014, we had the capacity to fund an additional $700 million under the facility based on the amount of eligible project costs already incurred. We anticipate making draws under the Department of Energy loan on at least a semi-annual basis through 2020 to meet our funding requirements as construction progresses.

    All of the debt under this loan will be secured ratably with all other debt under our first mortgage indenture.

    Bond Financings.    In June 2014, we issued $250 million of Series 2014A first mortgage bonds to provide long-term financing for general and environmental improvements to certain of our existing facilities and for general corporate purposes.

Capital Requirements

    Capital Expenditures.    As part of our ongoing capital planning, we forecast expenditures required for generating facilities and other capital projects. The table below details these forecasts for 2015 through 2017. Actual expenditures may vary from the estimates listed in the table because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor.

    In addition to the amounts reflected in the table above, we expect to incur capitalized costs of $1.06 billion to complete construction of Vogtle Units No. 3 and No. 4. For information regarding the financing for this project, see "– Financing Activities."

    We are currently subject to extensive environmental regulations and may be subject to future additional environmental regulations, including future implementation of existing laws and regulations. Since alternative legislative and regulatory environmental compliance programs continue to be debated on a national level, we cannot predict what capital costs may ultimately be required. Therefore, environmental expenditures included in the above table only include amounts related to budgeted projects to comply with existing and certain well-defined proposed rules and regulations and do not include amounts related to compliance with other, less certain proposed rules, such as the Clean Power Plan.

    Several major environmental compliance projects were completed over the last decade at our coal-fired plants to comply with the Georgia "multi-pollutant rule" and other regulatory requirements. These projects included the installation of flue gas desulfurization equipment for control of sulfur dioxide, selective catalytic reduction systems for control of oxides of nitrogen (an ozone precursor) and activated carbon injection and ancillary equipment (with baghouses at Plant Scherer) for control of mercury and other hazardous air pollutants. Our share of the cost of these projects was $854 million at Plant Scherer and $250 million at Plant Wansley.

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    Future environmental compliance projects at our coal-fired plants that are expected to be necessary to comply with EPA's final 316(b) (cooling water intake) rule, final coal combustion residuals rule, and proposed effluent limitations guidelines rule include i) closed cycle cooling studies and monitors, ii) potential conversion to dry ash handling, iii) potential new ash landfills, iv) groundwater monitoring and possible ash pond closure, and v) physical, chemical and biological wastewater treatment plants. The estimated cost to complete these projects beyond the three years reflected in the table, as well as miscellaneous additions and replacements for the recently completed projects through 2021, is $176 million.

    Depending on how we and the other co-owners of Plants Wansley and Scherer choose to comply with any future legislation or regulations, both capital expenditures and operating expenditures may be impacted. As required by the wholesale power contracts, we expect to be able to recover from our members all capital and operating expenditures made in complying with current and future environmental regulations.

    For additional information regarding environmental regulation, see "BUSINESS – REGULATION – Environmental."

    Contractual Obligations.    The table below reflects, as of December 31, 2014, our contractual obligations for the periods indicated.

Inflation

    As with utilities generally, inflation has the effect of increasing the cost of our operations and construction program. Operating and construction costs have been less affected by inflation over the last few years because rates of inflation have been relatively low.

Credit Rating Risk

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

    We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable collateral. Our primary exposure to potential collateral postings is at rating levels of BBB-/Baa3 or below. As of December 31, 2014, our maximum potential collateral requirements were as follows:

    At senior secured rating levels:

•

a total of approximately $50 million at a senior secured level of BBB-/Baa3,

•

a total of approximately $194 million at a senior secured level of BB+/Ba1 or below, and

    At senior unsecured or issuer rating levels:

•

a total of approximately $17.7 million at a senior unsecured or issuer rating level of BB+/Ba1 or below.

    The Rural Utilities Service Loan Contract contains covenants that, upon a credit rating downgrade below investment grade by two rating agencies, could result in restrictions on issuing debt. Certain of our pollution control bond agreements contain provisions based on

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the ratings assigned to the bonds (which could be related to either our rating or a bond insurer's rating if the bonds are insured) that, upon a credit rating downgrade below specified levels, could result in increased interest rates. Also, borrowing rates and commitment fees in two of our line of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants and provisions, however, would result in acceleration of any debt due to credit rating downgrades.

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

Off-Balance Sheet Arrangements

    We do not currently have any material off-balance sheet arrangements.

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ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

    Due to our cost-based rate structure, we have limited exposure to market risks. However, changes in interest rates, equity prices, and commodity prices may result in fluctuations in member rates. We use derivatives only to manage this volatility and do not use derivatives for speculative purposes.

    The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in July 2010 could impact our use of over-the-counter derivatives. As a commercial end-user, we are exempt from certain provisions of the Dodd-Frank Act. In addition, our cooperative status exempts our transactions with certain other cooperatives from additional requirements. We are however subject to recordkeeping and reporting requirements, and we may be subject to additional regulations as they are finalized. Such regulations may impose additional requirements on the use of over-the-counter derivatives and could affect the availability and cost of over-the-counter derivatives. The full and final impact and cost of the Dodd-Frank Act, which we do not expect to be significant, cannot be determined until all regulations are finalized. For additional information regarding our rate structure, see "BUSINESS – OGLETHORPE POWER CORPORATION – Electric Rates."

    We have an executive risk management and compliance committee that provides general oversight over corporate compliance and all risk management activities, including, but not limited to, commodity trading, fuels management, insurance procurement, debt management, investment portfolio management, environmental compliance, and electric reliability compliance. This committee is comprised of our chief executive officer, chief operating officer, chief financial officer and the executive vice president, member and external relations. The risk management and compliance committee has implemented comprehensive risk management policies to manage and monitor credit, market price, and other corporate risks. These policies also specify controls and authorization levels related to various risk management activities. The committee frequently meets to review corporate exposures, risk management strategies, hedge positions, and compliance matters. The audit committee of our board of directors receives regular reports on corporate exposures, risk management and compliance activities and the actions of the risk management and compliance committee. For further discussion of our board of director's oversight of risk management and compliance, see "DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE – Board of Directors' Role in Risk Oversight."

Interest Rate Risk

    At December 31, 2014, we were exposed to the risk of changes in interest rates related to our $607 million of variable rate debt, which includes $234 million of commercial paper outstanding (which typically has maturities of between 1 and 90 days) and $368 million of pollution control bond debt (including variable rate demand bonds subject to repricing weekly and auction rate securities subject to repricing every 35 days). At December 31, 2014, the weighted average interest rate on this variable rate debt was 0.19%. If, during 2014, interest rates on this debt changed a hypothetical 100 basis points on the respective repricing dates and remained at that level for the remainder of the year, annual interest expense would change by approximately $6 million.

    Our objective in managing interest rate risk is to maintain a balance of fixed and variable rate debt that will lower our overall borrowing costs within reasonable risk parameters. At December 31, 2014, we had 8.1% of our total debt, including commercial paper and capital lease debt, in a variable rate mode.

    The operative documents underlying the pollution control bond debt contain provisions that allow us to convert the debt to a variety of variable interest rate modes (such as daily, weekly, monthly, commercial paper, or term rate mode), or to convert the debt to a fixed rate of interest to maturity. Having these interest rate conversion options improves our ability to manage our exposure to variable interest rates.

    In addition to interest rate risk on existing debt, we are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. To mitigate the risk of rising interest rates, in the fourth quarter of 2011, we hedged a portion of our interest rate risk related to the financing of the new Vogtle units. Under this program, we made upfront premium payments of $100 million to purchase interest rate options to hedge the interest rates on approximately $2.2 billion of the debt needed to finance the new Vogtle units.

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    The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 151 basis points above the corresponding LIBOR swap rates that were in effect as of December 31, 2014 and the weighted average fixed rate is 4.05%. Swaptions having notional amounts totaling $563,425,000 expired without value during the twelve months ended December 31, 2014. The remaining swaptions expire quarterly through 2017.

    We paid the entire premium at the time we entered into these swaption transactions and have no additional payment obligations. However, upon expiration of the swaptions, each counterparty will be obligated to pay us the cash value of the swaption, if any. The counterparties for these swaptions consist of four large banks with average ratings ranging from A to AA. To manage our credit exposure to these counterparties, the agreements we have with the counterparties contain support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds range from $0 to $10 million depending on each counterparty's credit rating.

    We expect to defer any gains or losses from the change in fair value of each swaption and related carrying and other incidental costs. The deferred costs, which are not expected to exceed $120 million, and deferred gains, if any, from the sale or settlement of the swaptions will then be amortized and collected in rates over the life of the $2.2 billion of debt that we hedged with the swaptions.

Capital Leases

    We entered into a power purchase and sale agreement with Doyle I, LLC to purchase all of the output from a five-unit gas-fired generation facility. The Doyle agreement is reported on our balance sheet as a capital lease. The lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00%. At December 31, 2014, the weighted average interest rate on the lease obligation was 5.98%. We have exercised our option to purchase Doyle and expect to close on the acquisition in the third quarter of 2015.

Equity Price Risk

    We maintain external trust funds (reflected as "Nuclear decommissioning trust fund" on the balance sheet) to fund our share of certain costs associated with the decommissioning of our nuclear plants as required by the Nuclear Regulatory Commission (see Note 1 of Notes to Consolidated Financial Statements). We also maintain an internal reserve for decommissioning (included in "Long-term investments" on the balance sheet) from which funds can be transferred to the external trust fund, if necessary.

    The allocation of equity and fixed income securities in both the external and internal funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the equity portion of these funds is exposed to price fluctuations in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the funds and periodically review asset allocation in accordance with our nuclear decommissioning fund investment policy. Our investment policy establishes targeted and permissible investment allocation ranges for equity and fixed income securities. The targeted asset allocation is diversified among various asset classes and investment styles. Specific investment guidelines are established with each of the investment advisors that are selected to manage a particular asset class or subclass.

    The investment guidelines for equity securities typically limit the type of securities that may be purchased and the concentration of equity holdings in any one issuer and within any one sector. With respect to fixed-income securities, the investment guidelines set forth limits for the type of bonds that may be purchased, state that investments be primarily in

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securities with an assigned investment grade rating of BBB- or above and establish that the average credit quality of the portfolio typically be A+/A1 or higher.

    A 10% decline in the value of the internal and external funds' equity securities as of December 31, 2014 would result in a loss of value to the funds of approximately $27 million. For further discussion on our nuclear decommissioning trust funds, see Note 1 of Notes to Consolidated Financial Statements.

Commodity Price Risk

Coal

    We are also exposed to the risk of changing prices for fuels, including coal and natural gas. We have interests in 1,501 megawatts of coal-fired nameplate capacity at Plants Scherer and Wansley. We purchase coal under term contracts and in spot-market transactions. Some of our coal contracts provide volume flexibility and most have fixed or capped prices. We anticipate that our existing contracts and stockpiles will provide fixed prices for 100% of our remaining 2015 forecasted coal requirements at Plants Scherer and Wansley, respectively, and 66% and 100% of our forecasted 2016 coal requirements at Plants Scherer and Wansley, respectively.

    The objective of our coal procurement strategy is to ensure reliable coal supply and some price stability for our members. Our strategy focuses on coal commitments for up to 7 years. The procurement guidelines provide for layering in fixed and/or capped prices by annually entering into coal contracts for a portion of projected coal need for up to 7 years.

Natural Gas

    We own, lease or operate eight gas fired generation facilities totaling 4,170 megawatts of nameplate capacity. See "PROPERTIES – Generating Facilities" and "BUSINESS – OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources – Smarr EMC."

    We maintain a natural gas hedge program, which assists our participating members in managing potential fluctuations in our power rates to them due to changes in the market price of natural gas. Currently, approximately 15 of our members have elected to participate in our natural gas hedging program. This program layers in fixed prices over a rolling eight-quarter to ten-quarter time horizon using natural gas swap arrangements for a portion of the forecasted gas requirements related to the gas-fired resources that we manage and/or operate. We also use natural gas swap arrangements to hedge natural gas requirements associated with short-term electricity sales into the wholesale market. Under these swap agreements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. If the natural gas swaps had been terminated on December 31, 2014, we would have made a net payment of approximately $18.9 million. As of December 31, 2014, approximately 49% of our 2015 total system forecasted natural gas requirements (including requirements for the Smarr facilities) were hedged under swap arrangements. A hypothetical 10% decline in the market price of natural gas would have resulted in a decrease of approximately $8.0 million to the fair value of our natural gas swap agreements. Additional members may elect to participate in our natural gas hedging program, and participating members may choose to discontinue their participation in this program at any time.

Changes in Risk Exposure

    Our exposure to changes in interest rates, the price of equity securities we hold, and commodity prices have not changed materially from the previous reporting period.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index To Financial Statements

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 2014, 2013 and 2012

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE MARGIN
For the years ended December 31, 2014, 2013 and 2012

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2014 and 2013

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2014 and 2013

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 2014 and 2013

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31, 2014, 2013 and 2012

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND
ACCUMULATED OTHER COMPREHENSIVE MARGIN (DEFICIT)
For the years ended December 31, 2014, 2013 and 2012

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2014, 2013 and 2012

1. Summary of significant accounting policies:

a. Business description

    Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, Georgia that operates on a not-for-profit basis. We are owned by 38 retail electric distribution cooperative members in Georgia. We provide wholesale electric power from a combination of owned and co-owned generating units of which our ownership share totals 7,063 megawatts of summer planning reserve capacity. We also manage and operate Smarr EMC which owns 718 megawatts of summer planning reserve capacity. Georgia Power Company is a co-owner and the operating agent of our nuclear and coal-fired generating units. Our members in turn distribute energy on a retail basis to approximately 4.2 million people.

b. Basis of accounting

    Our consolidated financial statements include our accounts and the accounts of our majority-owned and controlled subsidiaries. We have determined that there are no accounts of variable interest entities for which we are the primary beneficiary. We have eliminated any intercompany profits and transactions in consolidation.

    We follow generally accepted accounting principles in the United States. We maintain our accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service. We also apply the accounting guidance for regulated operations.

    The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2014 and 2013 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2014. Actual results could differ from those estimates.

c. Patronage capital and membership fees

    We are organized and operate as a cooperative. Our members paid a total of $190 in membership fees. Patronage capital includes retained net margin. Any excess of revenue over expenditures from operations is treated as advances of capital by our members and is allocated to each of them on the basis of their fixed percentage capacity cost responsibilities in our generation and purchased power resources.

    Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. 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, (i) an event of default exists under the indenture, (ii) our equity as of the end of the 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 not less than 30% of our long-term debt and equities.

d. Accumulated other comprehensive margin (deficit)

    The table below provides detail regarding the beginning and ending balance for each classification of other comprehensive margin (deficit) along with the amount of any reclassification adjustments included in net margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin (Deficit). Our effective tax rate is zero; therefore, all amounts below are presented net of tax.

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e. Margin policy

    We are required under our first mortgage indenture to produce a margins for interest ratio of at least 1.10 for each fiscal year. For the years 2014, 2013 and 2012, we achieved a margins for interest ratio of 1.14.

f. Operating revenues

    Electricity revenues are recognized when capacity and energy are provided. Operating revenues from sales to members consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Capacity revenues recover our fixed costs plus a targeted margin and are charged regardless of whether our generation and purchased power resources are dispatched to produce electricity. Capacity revenues are based on an annual budget and, notwithstanding budget adjustments to meet our targeted margin, are recorded equally throughout the year. Energy revenues recover variable costs, such as fuel, incurred to generate or purchase electricity and are recorded such that energy revenues equal the actual energy costs incurred.

    Operating revenues from sales to non-members consists primarily of capacity and energy sales at Smith. Energy sales accounted for a substantial portion of our sales to non-members in 2014 and all of the sales to non-members in 2013. In 2012, non-member sales were primarily comprised of capacity and energy sales to Georgia Power Company in connection with a power purchase agreement that expired in May 2012, as well as sales to other non-members.

    The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2014, 2013 and 2012:

    We have two rate management programs that allow us to expense and recover certain costs on a current basis that would otherwise be deferred or capitalized. The subscribing members of Smith and/or Vogtle Units No. 3 and No. 4, can elect to participate in one, both or neither of these two programs on an annual basis. The Smith program allows for the accelerated recovery of deferred net costs related to Smith. The Vogtle program allows for the recovery of financing costs associated with the construction of Vogtle Units No. 3 and No. 4 on a current basis. Under these programs, amounts billed to participating members in 2014, 2013 and 2012 were $14,991,000, $13,962,000 and $26,149,000, respectively.

g. Receivables

    A substantial portion of our receivables are related to electricity sales to our members. These receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs. Member receivables at December 31, 2014 and 2013 were $114,808,000 and $117,287,000, respectively. The remainder of our receivables is primarily related to transactions with affiliated companies, electricity sales to non-members and to interest income on investments. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period the amounts are determined to be uncollectible.

h. Nuclear fuel cost

    The cost of nuclear fuel, including a provision for the disposal of spent fuel, is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2014, 2013 and 2012 amounted to $85,166,000, $86,828,000, and $81,723,000, respectively.

    Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants has pursued and continues to pursue legal remedies against the Department of Energy for breach of contract.

    On April 5, 2012, the U.S. Court of Federal Claims issued a final order for judgment in favor of Georgia Power in a lawsuit seeking damages for spent nuclear fuel storage costs incurred at Plant Hatch and Plant Vogtle Units No. 1 and No. 2 from 1998 through 2004. Our ownership share of the $54,017,000 total award was $16,205,000. The judgment was recorded in June 2012 and resulted in a $9,679,000 reduction in total operating expenses and a $6,526,000 reduction to plant in service.

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    On December 14, 2014, the U.S. Court of Federal Claims issued a judgment in favor of Georgia Power, as agent for the co-owners, to recover spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering the period of January 1, 2005 through December 31, 2010. Our ownership share of the $36,474,000 total award is approximately $10,940,000. No amounts have been recognized in the financial statements as of December 31, 2014 for this claim.

    On March 4, 2014, Georgia Power, as agent for the co-owners, filed a claim seeking damages for spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 covering a period of January 1, 2011 through December 31, 2013. Damages will continue to accumulate until the issue is resolved or storage is provided. No amounts have been recognized in the financial statements as of December 31, 2014 for this claim. The final outcome of these matters cannot be determined at this time.

    Both Plant Hatch and Plant Vogtle have on-site dry spent storage facilities in operation. Facilities at both plants can be expanded to accommodate spent fuel through the expected life of each plant.

i. Asset retirement obligations and other retirement costs

    Asset retirement obligations are legal obligations associated with the retirement of long-lived assets. These obligations represent the present value of the estimated costs for an asset's future retirement and are recorded in the period in which the liability is incurred. The liabilities we have recognized primarily relate to the decommissioning of our nuclear facilities. In addition, we have retirement obligations related to ash ponds, gypsum, landfill sites and asbestos removal. Under the accounting provision for regulated operations, we record a regulatory asset or liability to reflect the difference in timing of recognition of the costs related to nuclear and coal ash related decommissioning for financial statement purposes and for ratemaking purposes.

    Periodically, we obtain revised asset retirement obligation cost studies associated with our nuclear and fossil plants estimated future decommissioning. Actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, regulatory requirements, technology, and changes in costs of labor, material and equipment. The estimated costs of nuclear and ash pond decommissioning are based on the most recent studies performed in 2012. See note 1j for additional information regarding nuclear decommissioning cost studies.

    The following table reflects the details of the Asset Retirement Obligations included in the consolidated balance sheets for the years 2014 and 2013.

    We have established external trust funds to comply with the Nuclear Regulatory Commission regulations. See note 1j for information regarding the nuclear decommissioning trust fund.

    Accounting standards for asset retirement and environmental obligations do not apply to retirement costs for which there is no legal obligation to retire the asset, and non-regulated entities are not allowed to accrue for such future retirement costs. We continue to recognize retirement costs for these other obligations in our depreciation rates under the accounting provisions for regulated operations. Accordingly, the accumulated retirement costs for other obligations are reflected as a regulatory liability in our balance sheets. For information regarding accumulated retirement costs for other obligations, see Note 1r.

j. Nuclear decommissioning

    The Nuclear Regulatory Commission (NRC) requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. We have established external trust funds to comply with the NRC's regulations. Based on current funding and cost study estimates, we expect the current balances and anticipated investment earnings in our external trust funds to be sufficient to meet our future nuclear decommissioning obligations. As such, in 2014 and 2013, no additional amounts were contributed to the external trust funds. The funds set aside for decommissioning are managed by unrelated third party investment managers with the discretion to buy, sell and invest pursuant to investment objectives and restrictions set forth in agreements entered into between us and the investment managers. The funds are invested in a diversified mix of equity and fixed income securities.

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We record the investment securities held in the nuclear decommissioning trust fund, which are classified as available-for-sale, at fair value, as disclosed in Note 2. Because day-to-day investment decisions are made by third party investment managers, the ability to hold investments in unrealized loss positions is outside our control.

    In addition to the external trust funds, we maintain unrestricted investments internally designated for nuclear decommissioning. These internal funds will be utilized to fund the external trust funds should additional funding be required. At December 31, 2014 and 2013, we held approximately $59,080,000 and $52,742,000 in long-term investments associated with these internal funds. We collected from our members an additional $2,975,000 for nuclear decommissioning and contributed that amount to the internal funds during 2014.

    Unrealized gains and losses of the nuclear decommissioning funds that would be recorded in earnings or other comprehensive margin (deficit) by a non-regulated entity are directly deducted from or added to the regulatory asset or liability for asset retirement obligations in accordance with our rate-making treatment. Realized gains and losses on the nuclear decommissioning funds are also recorded to the regulatory asset or liability.

    Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service. Actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. The estimated costs of decommissioning are based on the most current study performed in 2012. Our portion of the estimated costs of decommissioning co-owned nuclear facilities were as follows:

    In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.4%. We assume a 6.0% earnings rate for our decommissioning trust fund assets. Since inception in 1990 through 2014, the nuclear decommissioning trust fund has produced an average annualized return of approximately 7.4%. Notwithstanding the results of revised site studies, our management believes that any increase in cost estimates of decommissioning can be recovered in future rates.

k. Depreciation

    Depreciation is computed on additions when they are placed in service using the composite straight-line method. The depreciation rates for steam and nuclear in the table below reflect revised rates from 2011 depreciation rate studies. Annual depreciation rates, as approved by the Rural Utilities Service, in effect in 2014, 2013 and 2012 were as follows:

    Depreciation expense for the years 2014, 2013 and 2012 was $178,302,000, $171,240,000, and $164,901,000, respectively.

l. Electric plant

    Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction and allocable overheads. For the years ended 2014, 2013 and 2012, the allowance for funds used during construction rates were 4.97%, 4.93% and 5.12%, respectively.

    Maintenance and repairs of property and replacements and renewals of items determined to be less than units of property are charged to expense. Replacements and renewals of items considered to be units of property are charged to the plant accounts. At the time properties are disposed of, the original cost, plus cost of removal, less salvage of such property, is charged to the accumulated provision for depreciation.

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m. Cash and cash equivalents

    We consider all temporary cash investments purchased with an original maturity of three months or less to be cash equivalents. Temporary cash investments with maturities at the time of purchase of more than three months are classified as short-term investments.

n. Restricted cash and investments

    At 2014 and 2013, we had restricted cash and investments totaling $365,585,000 and $307,817,000, respectively, of which $118,390,000 and $34,975,000, respectively was classified as long-term. Restricted cash balances consist primarily of funds posted as collateral by counterparties to our interest rate options. Restricted investments represent funds on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted investments will be utilized for future Rural Utilities Service Federal Financing Bank debt service payments. The funds on deposit in the Cushion of Credit earn interest at a rate of 5% per annum.

o. Inventories

    We maintain inventories of fossil fuel and spare parts, including materials and supplies for our generation plants. These inventories are stated at weighted average cost on the accompanying balance sheets.

    The fossil fuel inventories primarily include the direct cost of coal and related transportation charges. The cost of fossil fuel inventories is carried at weighted average cost and is charged to fuel expense as consumed based on weighted average cost. The spare parts inventories primarily include the direct cost of generating plant spare parts. The spare parts inventory is carried at weighted average cost and the parts are charged to expense or capitalized, as appropriate when installed.

    At 2014 and 2013, fossil fuels inventories were $98,789,000 and $124,359,000, respectively. Inventories for spare parts at 2014 and 2013 were $172,060,000 and $161,809,000, respectively.

p. Deferred charges and other assets

    We account for debt issuance costs as deferred debt expense. Deferred debt expense is amortized to expense on a straight-line basis over the life of the respective debt issues, which approximates the effective interest rate method. As of December 31, 2014, the remaining amortization periods for debt issuance costs range from approximately 1 to 36 years.

q. Deferred credits and other liabilities

    We have a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount based on our avoided cost of borrowing. The prepayments are credited against the participating members' power bills in the month(s) agreed upon in advance. The discounts are credited against the power bills and are recorded as a reduction to member revenues. The prepayments are being credited against members' power bills through January 2018, with the majority of the balance scheduled to be credited by the end of 2015.

    We have recorded a liability for a power sale agreement assumed in conjunction with the Hawk Road acquisition in May 2009. The liability is being amortized over the remaining life of the agreement which ends in 2015.

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r. Regulatory assets and liabilities

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

    The following regulatory assets and liabilities are reflected on the accompanying balance sheets as of December 31, 2014 and 2013:

s. Related parties

    We and our 38 members are members of Georgia Transmission. Georgia Transmission provides transmission services to its members for delivery of its members' power purchases from us and other power suppliers. We have entered into an agreement with Georgia Transmission to provide transmission services for third party transactions and for service to our own facilities. For 2014, 2013, and 2012, we incurred expenses from Georgia Transmission of $27,893,000, $27,599,000, and $26,035,000, respectively.

    We, Georgia Transmission and 37 of our members are members of Georgia Systems Operations. Georgia Systems Operations operates the system control center and currently provides us system operations services and administrative support services. For 2014, 2013, and 2012, we incurred expenses from Georgia Systems Operations of $23,351,000, $20,354,000, and $18,870,000, respectively.

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t. Other income

    The components of other income within the Consolidated Statement of Revenues and Expenses were as follows:

u. New accounting pronouncements

    In May 2014, the Financial Accounting Standards Board (FASB) issued "Revenue from Contracts with Customers" (Topic 606). The new revenue standard requires that an entity recognize revenue to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods and services. The standard is effective for the annual reporting period beginning after December 15, 2016 and early adoption is not permitted. We are currently evaluating the future impact of this standard to our consolidated financial position or results of operations.

2. Fair Value:

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

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

•

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

•

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

•

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

    Assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

(1)

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



(2)

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



(3)

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

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    The table below details assets and liabilities measured at fair value on a recurring basis for the periods ended December 31, 2014 and 2013, respectively.

 

    The Level 2 investments above in corporate bonds and agency mortgage and asset backed securities may not be exchange traded. The fair value measurements for these investments are based on a market approach, including the use of observable inputs. Common inputs include reported trades and broker/dealer bid/ask prices. The fair value of the Level 2 investments above in international equity trust are calculated based on the net asset value per share of the fund. There are no unfunded commitments for the international equity trust and redemption may occur daily with a three-day redemption notice period.

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    The following tables present the changes in Level 3 assets measured at fair value on a recurring basis during the years ended 2014 and 2013, respectively.

 

    We estimate the value of the interest rate options as the sum of time value and any intrinsic value minus a counterparty credit adjustment. Intrinsic value is the value of the underlying swap, which we are able to calculate based on the forward LIBOR swap rates, the fixed rate on the underlying swap, the time to expiration, the term of the underlying swap and discount rates, all of which we are able to effectively observe. Time value is the additional value of the swaption due to the fact that it is an option. We estimate the time value using an option pricing model which, in addition to the factors used to calculate intrinsic value, also takes into account option volatility, which we estimate based on option valuations we obtain from various sources. We estimate the counterparty credit adjustment by observing credit attributes, including the credit default swap spread of entities similar to the counterparty and the amount of credit support that is available for each swaption. Since the primary component of the LIBOR swaptions' value is time value, which is based on estimated option volatility derived from valuations of comparable instruments that are generally not publicly available, we have categorized these LIBOR swaptions as Level 3. We believe the estimated fair values for the LIBOR swaptions we hold are based on the most accurate information available for these types of derivative contracts. For additional information regarding our interest rate options, see Note 3.

    The estimated fair values of our long-term debt, including current maturities at December 31, 2014 and 2013 were as follows (in thousands):

    The estimated fair value of long-term debt is classified as Level 2 and is estimated based on observed or quoted market prices for the same or similar issues or on current rates offered to us for debt of similar maturities. The primary sources of our long-term debt consist of first mortgage bonds, pollution control revenue bonds and long-term debt issued by the Federal Financing Bank that is guaranteed by the Rural Utilities Service or the U.S. Department of Energy. We also have small amounts of long-term debt provided by National Rural Utilities Cooperative Finance Corporation (CFC) and by CoBank, ACB. The valuations for the first mortgage bonds and the pollution control revenue bonds were obtained from third party investment banking firms and a third party subscription service, and are based on secondary market trading of our debt. Valuations for debt issued by the Federal Financing Bank are based on U.S. Treasury rates as of

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December 31, 2014 and 2013 plus an applicable spread, which reflects our borrowing rate for new loans of this type from the Federal Financing Bank. The rates on the CFC debt are fixed and the valuation is based on rate quotes provided by CFC. We use an interest rate quote sheet provided by CoBank for valuation of the CoBank debt, which reflects current rates for a similar loan.

    For cash and cash equivalents, restricted cash and receivables, the carrying amount approximates fair value because of the short-term maturity of those instruments.

3. Derivative instruments:

    Our risk management and compliance committee provides general oversight over all risk management and compliance activities, including but not limited to, commodity trading, investment portfolio management and interest rate risk management. We use commodity trading derivatives to manage our exposure to fluctuations in the market price of natural gas. To hedge the risk of rising interest rates on a portion of our anticipated long-term debt to be incurred in connection with capital expenditures, we have entered into interest rate options. We do not apply hedge accounting for any of these derivatives, but apply regulatory accounting. Consistent with our rate-making, unrealized gains or losses on our natural gas swaps and interest rate options are reflected as regulatory assets or liabilities, as appropriate.

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

    It is possible that volatility in commodity prices and/or interest rates could cause us to have credit risk exposures with one or more counterparties. We currently have credit risk exposure to our interest rate options counterparties. If such counterparties fail to perform their obligations, we could suffer a financial loss. However, as of December 31, 2014, all of the counterparties with transaction amounts outstanding under our hedging programs are rated investment grade by the major rating agencies or have provided a guaranty from one of their affiliates that is rated investment grade.

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

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

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

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

    At December 31, 2014 and 2013, the estimated fair value of our natural gas contracts were a net liability of $18,914,000 and a net asset of $1,011,000, respectively.

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    As of December 31, 2014 and 2013, neither we nor any counterparties were required to post credit support or collateral under the natural gas swap agreements. If the credit-risk-related contingent features underlying these agreements were triggered on December 31, 2014 due to our credit rating being downgraded below investment grade, we would have been required to post letters of credit of $18,914,000 with our counterparties.

    The following table reflects the volume activity of our natural gas derivatives as of December 31, 2014 that is expected to settle or mature each year:

    Interest rate options.    We are exposed to the risk of rising interest rates due to the significant amount of new long-term debt we expect to incur in connection with anticipated capital expenditures, particularly the construction of Vogtle Units No. 3 and No. 4. In fourth quarter of 2011, we purchased LIBOR swaptions at a cost of $100,000,000 with a total notional amount of approximately $2,200,000,000 to hedge the interest rates on a portion of the debt that we are incurring to finance the two additional nuclear units at Plant Vogtle. Since inception, swaptions having a notional amount of approximately $1,317,877,000 have expired and as of December 31, 2014 the remaining notional amount of our outstanding swaptions was approximately $861,327,000.

    The LIBOR swaptions are each designed to cap our effective interest rate at a specified fixed interest rate on a specified option expiration date. This is accomplished by means of a payment of the cash settlement value our counterparties are obligated to make to us if prevailing fixed LIBOR swap rates exceed the specified fixed rate on the option expiration date. This payment would partially offset our interest costs, thereby reducing our effective interest rate. The cash settlement value would be zero if swap rates are at or below the specified fixed rate on the expiration date. The cash settlement value is calculated based on the value of an underlying swap which we have the right, but not the obligation, to enter into, which would begin on the option expiration date and extend until 2042 and under which we would pay the specified fixed rate and receive a floating LIBOR rate. The fixed rates on the unexpired swaptions we hold average 151 basis points above the corresponding LIBOR swap rates that were in effect as of December 31, 2014 and the weighted average fixed rate is 4.05%. Swaptions having notional amounts totaling $563,424,000 expired without value during the year ended December 31, 2014. The remaining swaptions expire quarterly through 2017.

    We paid all the premiums to purchase these LIBOR swaptions at the time we entered into these transactions. At December 31, 2014 and 2013, the fair value of these swaptions was approximately $4,371,000 and $63,471,000, respectively. To manage our credit exposure to our counterparties, we negotiated credit support provisions that require each counterparty to provide us collateral in the form of cash or securities to the extent that the value of the swaptions outstanding for that counterparty exceeds a certain threshold. The collateral thresholds can range from $0 to $10,000,000 depending on each counterparty's credit rating. As of December 31, 2014 and 2013, we held $0 and $34,970,000 of funds posted as collateral by the counterparties, respectively. The collateral received is recorded as restricted cash on our consolidated balance sheet. The liability associated with the collateral is recorded as an offset to the fair values of the swaptions, which are recorded within other deferred charges on the consolidated balance sheet, resulting in a net carrying amount of the interest rate options of $4,371,000 and $28,501,000 at December 31, 2014 and 2013, respectively.

    We are deferring unrealized gains or losses from the change in fair value of each LIBOR swaption and related carrying and other incidental costs in accordance with our rate-making treatment. The realized deferred costs and deferred gains, if any, from the settlement of the interest rate options will be amortized and collected in rates over the life of the $2.2 billion of debt that we hedged with the swaptions.

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    The following table reflects the remaining notional amount of forecasted debt issuances we have hedged in each year with LIBOR swaptions as of December 31, 2014.

    The table below reflects the fair value of derivative instruments and their effect on our consolidated balance sheets at December 31, 2014 and 2013.

    The following table presents the realized gains and (losses) on derivative instruments recognized in margin for the year ended December 31, 2014, 2013 and 2012.

    The following table presents the unrealized gains and (losses) on derivative instruments deferred on the balance sheet at December 31, 2014 and 2013.

    The following table presents the gross amounts of derivatives and their related offset amounts as permitted by their respective master netting agreements and obligations to return cash collateral at December 31, 2014 and 2013.

4. Investments:

Investments in debt and equity securities

    Investment securities we hold are classified as available-for-sale. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from patronage capital, except that, in accordance with our rate-making treatment, realized and unrealized gains and losses from investment securities held in the nuclear decommissioning funds are directly added to or deducted from the regulatory asset or liability for asset retirement obligations. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 80% of these gross unrealized losses were in effect for less than one year.

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    For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of December 31, 2014 and 2013:

    All of the available-for-sale investments are recorded at fair value in the accompanying consolidated balance sheets, therefore the carrying value equals the fair value.

    The contractual maturities of debt securities available-for-sale, which are included in the estimated fair value table above, at December 31, 2014 and 2013 are as follows:

    The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2014, 2013 and 2012:

Investment in associated companies

    Investments in associated companies were as follows at December 31, 2014 and 2013:

    The CFC investments are primarily in the form of capital term certificates and are required in conjunction with our membership in CFC. Accordingly, there is no market for these investments. The investments in CoBank and Georgia Transmission represent capital credits. Any distributions of capital credits are subject to the discretion of the board of directors of CoBank and Georgia Transmission. The investments in Georgia System Operations represent loan advances. Repayments of these advances are expected by December 2017.

    CT Parts, LLC is an affiliated organization formed by us and Smarr EMC for the purpose of purchasing and maintaining a spare parts inventory and administration of contracted services for combustion turbine generation facilities. Such investment is recorded at cost.

Rocky Mountain transactions

    In December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to six separate owner trusts for the benefit of three investors, referred to as owner participants, for a term equal to 120% of the estimated useful life of Rocky Mountain. Immediately thereafter, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation, or RMLC, for a term of 30 years under six separate leases. RMLC then subleased the undivided interests back to us under six separate leases for an identical term.

    In 2012, we terminated five of the six lease transactions prior to the end of their lease terms. The five leases were each owned by separate owner trusts for the benefit of two of the owner participants, and represented approximately 90% of the six original lease

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transactions. As a result, only one of the original lease arrangements, approximately 10% of the original lease transactions, remains in place. In connection with these terminations, we incurred termination costs of $22,500,000 and recognized $41,400,000 of the deferred net benefit associated with the terminated leases, resulting in a net gain on termination of $18,900,000. We have a guarantee for the basic rental payments under the remaining lease. The fair value amount relating to the guarantee of basic rent payments is immaterial to us principally due to the high credit rating of the payment undertaker. The basic rental payments remaining through the end of the lease are approximately $64,900,000.

    The assets of RMLC are not available to pay our creditors.

5. Income taxes:

    While we are a not-for-profit membership corporation formed under the laws of Georgia, we are subject to federal and state income taxation. As a taxable cooperative, we are allowed to deduct patronage dividends that we allocate to our members for purposes of calculating our taxable income. We annually allocate income and deductions between patronage and non-patronage activities and substantially all of our income is from patronage-sourced activities, resulting in no current period income tax expense or current or deferred income tax liability.

    Although we believe that treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment was not sustained, we believe that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on financial condition or results of operations and cash flows.

    We account for income taxes pursuant to the authoritative guidance for accounting for income taxes, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns.

    The difference between the statutory federal income tax rate on income before income taxes and our effective income tax rate is summarized as follows:

    The components of our net deferred tax assets and liabilities as of December 31, 2014 and 2013 were as follows:

    As of December 31, 2014, we have federal tax net operating loss carryforwards and alternative minimum tax credits as follows:

    The net operating loss expiration dates start in the year 2018 and end in the year 2020. Due to the tax basis method for allocating patronage and as shown by the above valuation allowance, it is not more likely than not that the deferred tax assets related to tax credits and net operating losses will be realized. Any future tax benefits realized as a result of monetizing the tax

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credits will require favorable tax legislation and are not expected to be material to the financial statements.

    The authoritative guidance for income taxes addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. We may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement.

    We file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year 2011 forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2011 forward. We have no liabilities recorded for uncertain tax positions.

6. Capital leases:

    In 1985, we sold and subsequently leased back from four purchasers their 60% undivided ownership interest in Scherer Unit No. 2. The gain from the sale is being amortized over the terms of the leases. In June 2012, we renewed the leases beyond their base terms. Three of the leases were extended for a period of 14.5 years through December 31, 2027 and one lease was extended for a period of 18 years through June 30, 2031.

    In 2000, we entered into a power purchase and sale agreement with Doyle I, LLC (Doyle Agreement), an affiliate of one of our members, to purchase all of the output from a five-unit generation facility (Doyle) for a period of 15 years, through August 24, 2015. We have exercised our option to purchase the facility and expect the acquisition to close on August 24, 2015.

    The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2014 are as follows:

    For Doyle, the lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00%. At December 31, 2014, the weighted average interest rate on the Doyle lease obligation was 5.98% as compared to 5.94% at December 31, 2013.

    The Scherer No. 2 leases and the Doyle Agreement are reported as capital leases. For rate-making purposes, however, we include the actual lease payments in our cost of service. The difference between lease payments and the aggregate of the amortization on the capital lease asset and the interest on the capital lease obligation is recognized as a regulatory asset or regulatory liability on the consolidated balance sheet. Capital lease amortization is recorded in depreciation and amortization expense.

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7. Debt:

    Long-term debt consists of first mortgage notes payable to the United States of America acting through the Federal Financing Bank and the Rural Utilities Service or the U.S. Department of Energy, first mortgage bonds payable, first mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds and first mortgage notes payable to CoBank and CFC. Substantially all of our owned tangible and certain of our intangible assets are pledged under our first mortgage indenture as collateral for the Federal Financing Bank notes, the first mortgage bonds, the first mortgage notes issued in conjunction with the sale of pollution control revenue bonds, and the CoBank and CFC first mortgage notes.

a)

Department of Energy Loan Guarantee:

    Pursuant to the loan guarantee program established under Title XVII of the Energy Policy Act of 2005 (the "Title XVII Loan Guarantee Program"), we and the U.S. Department of Energy, acting by and through the Secretary of Energy entered into a Loan Guarantee Agreement on February 20, 2014 (the "Loan Guarantee Agreement") pursuant to which the Department of Energy agreed to guarantee our obligations (the "Department of Energy Guarantee") under the Note Purchase Agreement dated as of February 20, 2014 (the "Note Purchase Agreement"), among us, the Federal Financing Bank and the Department of Energy and the Future Advance Promissory Note No. 1 and Future Advance Promissory Note No. 2, each dated February 20, 2014, made by us to Federal Financing Bank (the "Federal Financing Bank Notes" and together with the Note Purchase Agreement, the "FFB Credit Facility Documents"). The Federal Financing Bank Credit Facility Documents provide for a multi-advance term loan facility (the "Facility"), under which we may make term loan borrowings through 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 Vogtle Units No. 3 and No. 4 that are eligible for financing under the Title XVII Loan Guarantee Program ("Eligible Project Costs"). Aggregate borrowings under the Facility may not exceed the lesser of (i) 70% of Eligible Project Costs or (ii) $3,057,069,461, of which $335,471,604 is designated for capitalized interest.

    Under the Loan Guarantee Agreement, we are obligated to reimburse the Department of Energy in the event the Department of Energy is required to make any payments to the Federal Financing Bank under the Department of Energy Guarantee. Our payment obligations to the Federal Financing Bank under the Federal Financing Bank Notes and reimbursement obligations to the Department of Energy under the related reimbursement notes are secured equally and ratably with all of our other notes and obligations issued under our first mortgage indenture by a lien on substantially all of our owned tangible and certain of our intangible assets, including property we acquire in the future.

    Advances.    Advances may be requested under the Facility on a quarterly basis through December 31, 2020. On February 20, 2014, we made an initial borrowing in the principal amount of $725,000,000 at a fixed interest rate of 3.867% through February 20, 2044. In connection with the receipt of these funds, we repaid a like amount of outstanding short-term obligations, which included a $260,000,000 term loan originally due April 1, 2014 and $465,000,000 of commercial paper. These outstanding obligations were classified as long-term at December 31, 2013. On December 13, 2014, we received an additional $125,000,000 advance under the Facility at a fixed interest rate of 2.978% through February 20, 2044.

    Future advances are subject to satisfaction of customary conditions, as well as certification of compliance with the requirements of the Title XVII Loan Guarantee Program, accuracy of project-related representations and warranties, delivery of updated project-related information, certification regarding Georgia Power's compliance with certain obligations relating to the Cargo Preference Act, as amended, evidence of compliance with the prevailing wage requirements of the Davis-Bacon Act, as amended, and certification from Department of Energy's consulting engineer that proceeds of the advance are used to reimburse Eligible Project Costs.

    Maturity, Interest Rate and Amortization.    The final maturity date for each advance under the Facility is February 20, 2044. Interest is payable quarterly in arrears on February 20, May 20, August 20 and November 20 of each year. Principal and interest payments will begin on February 20, 2020. Interest accrued and payable through November 20, 2019, up to a maximum of

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$335,471,604, is reflected as additional borrowings under the Facility. As of December 31, 2014, $24,607,000 of interest is reflected as long-term debt on our consolidated balance sheet.

    Under Future Advance Promissory Note No. 1, we may select an interest rate period applicable to each advance, with such interest rate periods ranging from three months to the final maturity date. All advances under Future Advance Promissory Note No. 2 will bear a fixed rate of interest through the final maturity date. Under both Federal Financing Bank Notes, the interest rates during the applicable interest rate periods will equal the current average yield on U.S. Treasuries of comparable maturity at the beginning of the interest rate period, plus a spread equal to 0.375%.

    In connection with our entry into the Loan Guarantee Agreement and the FFB Credit Facility Documents, we incurred issuance costs of approximately $51,000,000, which will be amortized over the life of the borrowings under the Facility. Issuance costs include fees paid to the Department of Energy, legal and consulting expenses and costs for compliance with certain federal requirements (including compliance with the Davis-Bacon Act).

b)

Rural Utilities Service Guaranteed Loans:

    During 2014, we received advances on Rural Utilities Service-guaranteed Federal Financing Bank loans totaling $37,362,000 for long-term financing of general and environmental improvements at existing plants.

    In February 2015, we received an additional $113,718,000 in advances on Rural Utilities Service-guaranteed Federal Financing Bank loans for long-term financing of general and environmental improvements at existing plants.

c)

Bond Issuance:

    On June 12, 2014, we issued $250,000,000 of 4.55% first mortgage bonds, Series 2014A, primarily for the purpose of repaying outstanding commercial paper issued for the interim financing of general and environmental capital expenditures at our existing generation facilities and for general corporate purposes. The bonds are secured under our first mortgage indenture.

d)

Credit Facilities

    As of December 31, 2014, we had $1,775,000,000 of committed credit arrangements comprised of five separate facilities with maturity dates that range from June 2015 to December 2018. These credit facilities are for general working capital purposes, issuing letters of credit and backing up outstanding commercial paper. Under our unsecured committed lines of credit that we had in place at December 31, 2014, we had the ability to issue letters of credit totaling $970,000,000 in the aggregate, of which $719,000,000 remained available. At December 31, 2014, we had 1) $251,000,000 under these lines of credit in the form of issued letters of credit supporting variable rate demand bonds and collateral postings to third parties, and 2) $234,000,000 dedicated under one of these lines of credit to support a like amount of commercial paper that was outstanding.

    On March 23, 2015, we entered into a $1,210,000,000 credit agreement with thirteen lenders, including the National Rural Utilities Cooperative Finance Corporation as administrative agent, to replace certain of our existing credit facilities in place at December 31, 2014. The new agreement expires on March 23, 2020. At December 31, 2014, we classified $133,600,000 in variable rate demand bonds supported by this new credit agreement as long-term debt.

    The weighted average interest rate on short-term borrowings was 0.28% at December 31, 2014 as compared to 0.29% at December 31, 2013.

    Maturities for long-term debt and capital lease obligations through 2019 are as follows:

    The weighted average interest rate for long-term debt and capital leases, excluding short-term borrowings classified as long-term, at December 31, 2014 and 2013 was 4.55% and 4.56%, respectively.

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8. Electric plant, construction and related agreements:

a. Electric plant

    We, along with Georgia Power, have entered into agreements providing for the purchase and subsequent joint operation of certain electric generating plants. Each co-owner is responsible for providing its' own financing. The plant investments disclosed in the table below represent our undivided interest in each plant. A summary of our plant investments and related accumulated depreciation as of December 31, 2014 and 2013 is as follows:

    Our proportionate share of direct expenses of joint operation of the above plants is included in the corresponding operating expense captions (e.g., fuel, production or depreciation) on the accompanying Statement of Revenues and Expenses.

b. Construction

    In 2008, Georgia Power, acting for itself and as agent for us, the Municipal Electric Authority of Georgia, and the City of Dalton, Georgia (collectively, the Co-owners), and Westinghouse Electric Company LLC (Westinghouse) and Stone & Webster, Inc. (collectively, the Contractor) entered into an engineering, procurement, and construction agreement (the EPC Agreement) to design, engineer, procure, construct, and test two AP1000 nuclear units with electric generating capacity of approximately 1,100 megawatts each and related facilities, structures, and improvements at Plant Vogtle (Vogtle Units No. 3 and No. 4).

    Under the EPC Agreement, the Co-owners will pay a purchase price that is subject to certain price escalation and adjustments, including fixed escalation amounts and 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 comply with schedule and performance guarantees. The Contractor's liability for those liquidated damages and for warranty claims is subject to a cap. In addition, the EPC Agreement provides for limited cost sharing by the Co-owners for increases to Contractor costs under certain conditions which have not occurred, with maximum exposure to us of $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. Our ownership interest and proportionate share of the cost to construct Vogtle Units No. 3 and No. 4 is 30%.

    The NRC certified the Westinghouse AP1000 Design Control Document (DCD) effective December 30, 2011. On February 10, 2012, the NRC issued combined construction permits and operating licenses (COLs) for Vogtle Units No. 3 and No. 4 which allowed full construction to begin. There have been technical and procedural challenges to the construction and licensing of these units and additional challenges at the federal and state level may arise as construction proceeds.

    During the development and construction process, issues have materialized that have impacted the original schedule and cost estimates. Most recently, in January 2015, the Contractor notified the Co-owners of the

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Contractor's proposed revised integrated project schedule for completion of Vogtle Units No. 3 and No. 4 which would delay the estimated in-service dates to the second quarter of 2019 and the second quarter of 2020, respectively. This represents an 18-month delay for each unit from the previously disclosed schedule which projected in-service dates for Vogtle Units No. 3 and No. 4 in the fourth quarter of 2017 and the fourth quarter of 2018, respectively. Georgia Power, on behalf of the Co-owners, has not agreed to any changes to the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively, and does not believe that the Contractor's proposed revision to the schedule reflects all efforts that may be possible to mitigate the Contractor's delay.

    During the extended construction period, we will continue to incur our share of owner-related costs, including property taxes, oversight costs, compliance costs, and other operational readiness costs and will also continue to incur financing costs. Although Georgia Power, on behalf of the Co-owners, has not accepted the revised schedule, we expect that each additional month delay beyond the previously disclosed in-service dates for Vogtle Units No. 3 and No. 4 of the fourth quarter of 2017 and the fourth quarter of 2018, respectively, will increase our previously disclosed project budget, which includes capital costs, allowance for funds used during construction and a contingency amount, of $4,500,000,000 by approximately $28,000,000 per month, which would increase our project budget to $5,000,000,000 should the entire eighteen-month delay be realized. Commercial responsibility for the revised commercial operation dates and additional costs remain in dispute.

    In addition, as construction continues, the risk remains that ongoing challenges with the Contractor's performance including additional challenges in its fabrication, assembly, delivery, and installation of the shield building and structural modules, delays in the receipt of the remaining permits necessary for the operation of Vogtle Units No. 3 and No. 4, or other issues could arise and may further impact the project schedule and cost. Additional claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction. Any of these claims or disputes may be resolved through formal and informal dispute resolution procedures under the EPC Agreement but also may be resolved through litigation. See Note 12a for information regarding nuclear construction contingencies.

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

    At December 31, 2014, our total Vogtle construction project costs were approximately $2,415,000,000.

9. Employee benefit plans:

    Our retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of his or her eligible annual compensation. At our discretion, we may match the employee's contribution and have done so each year of the plan's existence. Our current policy is to match the employee's contribution as long as there is sufficient margin to do so. The match, which is calculated each pay period, currently can be equal to as much as three-quarters of the first 6% of an employee's eligible compensation, depending on the amount and timing of the employee's contribution. Our contributions to the matching feature of the plan were approximately $1,205,000 in 2014, $1,161,000 in 2013 and $1,016,000 in 2012.

    Our 401(k) plan also includes an employer retirement contribution feature, which subject to IRS limitations, contributes 8% of an employee's eligible annual compensation. Our contributions to the employer retirement contribution feature of the 401(k) plan were approximately $2,441,000 in 2014, $2,289,000 in 2013 and $2,029,000 in 2012.

10. Nuclear insurance:

    The Price-Anderson Act, limits public liability claims that could arise from a single nuclear incident to $13,600,000,000. This amount is covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers (ANI), is carried by Georgia Power for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $375,000,000, a licensee of a nuclear power plant could be assessed a deferred premium of up to $127,000,000 per incident for each licensed reactor operated by it, but

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not more than $19,000,000 per reactor per incident to be paid in a calendar year. On the basis of our ownership interest in four nuclear reactors, we could be assessed a maximum of $152,000,000 per incident, but not more than $23,000,000 in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years, and exclude any applicable state premium taxes. The next scheduled adjustment is due no later than September 10, 2018.

    Georgia Power, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member of Nuclear Electric Insurance, Ltd. (NEIL), a mutual insurer established to provide property damage insurance coverage in an amount up to $1,500,000,000 for members' operating nuclear generating facilities. Additionally, there is coverage through NEIL for decontamination, excess property insurance, and premature decommissioning coverage up to $1,250,000,000 for nuclear losses in excess of the $1,500,000,000 primary coverage. On April 1, 2014, NEIL introduced a new excess non-nuclear policy providing coverage up to $750,000,000 for non-nuclear losses in excess of the $1,500,000,000 primary coverage.

    Georgia Power, on behalf of all the co-owners has purchased a builders' risk property insurance policy from NEIL for Vogtle Units No. 3 and No. 4. This policy provides $2,750,000,000 in limits for accidental property damage occurring during construction.

    Under each of the NEIL policies, members are subject to retroactive assessments in proportion to their premiums, if losses each year exceed the accumulated reserve funds available to the insurer. The portion of the current maximum annual assessment for Georgia Power that would be payable by Oglethorpe based on ownership share, is limited to approximately $36,000,000.

    Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12-month period is $3,200,000,000 plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

    For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are next to be applied toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to Georgia Power, for the benefit of all the co-owners, or to bond trustees as may be appropriate under the policies and applicable trust indentures.

    All retrospective assessments, whether generated for liability or property, may be subject to applicable state premium taxes. In the event of a loss, the amount of insurance available may not be adequate to cover property damage and other incurred expenses. Uninsured losses and other expenses could have a material adverse effect on our financial condition and results of operations.

11. Commitments:

a. Operating leases

    As of December 31, 2014, our estimated minimum rental commitments for our railcar leases for use at our coal-fired facilities over the next five years and thereafter are as follows:

    The rental expenses for the railcar leases are added to the cost of the fossil inventories and are recognized in fuel expense. Rental expenses totaled $5,139,000, $5,213,000 and $5,164,000 in 2014, 2013 and 2012, respectively.

b. Fuel

    To supply a portion of the fuel requirements to our generating units, Southern Nuclear on our behalf for nuclear fuel, and Georgia Power, on our behalf for coal, have entered into various long-term commitments for the procurement of coal and nuclear fuel. The contracts in most cases contain provision for price escalations, minimum and maximum purchase levels and other financial commitments. The value of the coal commitments is based on maximum coal prices and minimum volumes as provided in the contracts and does

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not include taxes, transportation, government impositions or railcar costs. For further discussion of total nuclear fuel expense, see Note 1h. As of December 31, 2014, our estimated minimum long-term commitments are as follows:

12. Contingencies and Regulatory Matters:

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

a. Nuclear Construction

    Under the EPC Agreement for Vogtle Units No. 3 and No. 4, the Co-owners and the Contractor have established both informal and formal dispute resolution procedures in order to resolve issues arising during the course of constructing a project of this magnitude. Georgia Power, on behalf of the Co-owners, has successfully initiated both formal and informal claims through these procedures, including ongoing claims. When matters are not resolved through these procedures, the parties may proceed to litigation. The Contractor and the Co-owners are involved in litigation with respect to certain claims that have not been resolved through the formal dispute resolution process.

    In July 2012, the Co-owners and Contractor began negotiations regarding costs associated with design changes to the DCD and delays in the project schedule related to the timing of approval of the DCD and issuance of the combined construction permits and operating licenses by the Nuclear Regulatory Commission, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the EPC Agreement. On November 1, 2012, the Co-owners filed suit against the Contractor in the U.S. District Court for the Southern District of Georgia, seeking a declaratory judgment that the Co-owners are not responsible for these costs. Also on November 1, 2012, the Contractor filed suit against the Co-owners in the U.S. District Court for the District of Columbia alleging the Co-owners are responsible for these costs. In August 2013, the U.S. District Court for the District of Columbia dismissed the Contractor's suit, ruling that proper venue is the U.S. District Court for the Southern District of Georgia. In March 2015, the U.S. Court of Appeals for the District of Columbia affirmed this dismissal which means the case will be tried in the U.S. District Court for the Southern District of Georgia. The portion of the additional costs claimed by the Contractor that would be attributable to us, based on our ownership interest, is approximately $280 million in 2008 dollars with respect to these issues. The Contractor has also asserted that it is entitled to extensions of the guaranteed substantial completion dates of April 2016 and April 2017 for Vogtle Units No. 3 and No. 4, respectively. On May 22, 2014, the Contractor filed an amended counterclaim to the lawsuit pending in the Southern District of Georgia alleging that (i) the design changes to the DCD imposed by the Nuclear Regulatory Commission have delayed module production and the impacts to the Contractor are recoverable by the Contractor under the EPC Agreement and (ii) the changes to the basemat rebar design required by the Nuclear Regulatory Commission caused additional costs and delays recoverable by the Contractor under the EPC Agreement. The Contractor did not specify amounts relating to these new allegations in its amended counterclaim; however, the Contractor has subsequently asserted related minimum damages, based on our ownership interest, of approximately $75 million. The Contractor may from time to time continue to assert that it is entitled to additional payments with respect to these new allegations, any of which could be substantial. Georgia Power, on behalf of the Co-owners, has not agreed with either the proposed cost or schedule adjustments or that the Co-owners have any responsibility for costs related to these issues. Litigation is ongoing and Georgia Power and the Co-owners intend to vigorously defend their positions. Georgia Power and the Co-owners also expect negotiations with the Contractor to continue with respect to cost and schedule during which time the parties will attempt to reach a mutually acceptable compromise of their positions.

    If any or all of these costs are ultimately imposed on the Co-owners, we will capitalize the costs attributable to us. As of December 31, 2014, no material amounts have been recorded related to this claim. Additional

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claims by the Contractor or Georgia Power, on behalf of the Co-owners, are also likely to arise throughout construction.

b. Patronage Capital Litigation

    On March 13, 2014, a lawsuit was filed in the Superior Court of DeKalb County, Georgia, against us, Georgia Transmission and three of our member distribution cooperatives. Plaintiffs filed an amended complaint on July 28, 2014. The amended complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives and seeks to certify a defendant class of all but one of our 38 members. It was filed by four former consumer-members of four of our members on behalf of themselves and a proposed class of all former consumer-members of our members. Plaintiffs claim that approximately 30% of all the defendants' total allocated patronage capital belongs to former consumer-members. Plaintiffs also allege that patronage capital owed to former consumer-members includes patronage capital allocated by us to our members but not yet distributed to our members. Plaintiffs claim that the patronage capital of former consumer-members held by defendants and the proposed defendant class should be retired immediately when the consumer-members end their membership by terminating service, or alternatively, according to a revolving schedule of no longer than 13 years from the date of its allocation and seek relief to effect such retirements. Plaintiffs further seek to require the defendants to adjust rates in order to establish and maintain reasonable reserves to fund patronage capital retirements on this basis. Plaintiffs also claim that defendants and the proposed defendant class should be required to adopt policies to periodically retire the patronage capital of all consumer-members on a revolving schedule of no longer than 13 years from the date of its allocation. Our first mortgage indenture restricts our ability to distribute patronage capital. Although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level sufficient so that we could comply with the current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiffs' demands would be significant for a period of years.

    On August 20, 2014, a second patronage capital lawsuit was filed in the Superior Court of DeKalb County against us, Georgia Transmission, and two of our member distribution cooperatives. The case was filed by two current consumer-members of the two member distribution cooperatives named in the lawsuit. Similar to the above described litigation, this complaint challenges the patronage capital distribution practices of Georgia's electric cooperatives; however, one notable difference is that the first case, described above, seeks to bring claims on behalf of former members while this second case seeks to bring claims on behalf of current members. The plaintiffs allege that the defendants have (i) retained patronage capital for an unreasonably long period of time; (ii) conspired with each other to deprive consumer-members of their patronage capital; and (iii) breached bylaw provisions allegedly requiring that patronage capital be retired when the financial condition of the cooperative will not be impaired. The plaintiffs seek unspecified damages and equitable relief, including an order declaring that the defendants be required to retire patronage capital "according to a regular, reasonable revolving plan." Similarly to the litigation described above, although not expected, if we were ordered by the Court to make distributions of our patronage capital, our first mortgage indenture would require us to raise our rates to a level where we could comply with current patronage capital distribution restrictions, and the rate increases required to meet the Plaintiff's demands could be significant for a period of years. The plaintiffs seek to certify three plaintiffs' classes but do not seek to certify a defendants' class.

    We intend to defend vigorously against all claims in the above-described litigation.

c. Environmental Matters

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

    In general, these and other types of environmental requirements are becoming increasingly stringent. Such requirements may substantially increase the cost of electric service, by requiring modifications in the design or operation of existing facilities or the purchase of

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

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

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

13. Purchase Agreements:

    On April 11, 2014, we signed a precedent agreement with Transcontinental Gas Pipeline Company, LLC (Transco) for additional firm natural gas transportation to our Smith facility. The additional firm transportation is contingent upon the construction of a new natural gas pipeline by Transco. Total fixed charges over the 25-year base term will be approximately $942,500,000. Our obligation to make payments begins when the pipeline expansion project is placed into service, which is projected to be May 1, 2017.

14. Quarterly financial data (unaudited):

    Summarized quarterly financial information for 2014 and 2013 is as follows:

    Our business is influenced by seasonal weather conditions. The negative net margins in the fourth quarter of 2014 and 2013 were due to reductions to revenue requirements in order to achieve the targeted margins for interest ratio of 1.14.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

    The Board of Directors and Members of Oglethorpe Power Corporation

    We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Oglethorpe Power Corporation as of December 31, 2014 and 2013, and the related consolidated statements of revenues and expenses, comprehensive margin, patronage capital and membership fees and accumulated other comprehensive margin (deficit), and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

    We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included the consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

    In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oglethorpe Power Corporation at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP                    

Atlanta, Georgia
March 26, 2015

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

    None.

ITEM 9A.    CONTROLS AND PROCEDURES

Management's Responsibility for Financial Statements

    Our management has prepared this annual report on Form 10-K and is responsible for the financial statements and related information included herein. These statements were prepared in accordance with generally accepted accounting principles and necessarily include amounts that are based on best estimates and judgments of management. Financial information throughout this annual report on Form 10-K is consistent with the financial statements.

    Management believes that our policies and procedures provide reasonable assurance that our operations are conducted with a high standard of business ethics. In management's opinion, our financial statements present fairly, in all material respects, our financial position, results of operations, and cash flows.

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

    Under the supervision and with the participation of our management, including the principal executive officer and principal financial officer, we conducted an evaluation of our disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2014 in providing a reasonable level of assurance that information we are required to disclose in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information we are required to disclose in such reports is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

    Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control – Integrated Framework (2013 framework) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

    Based on our evaluation under the framework in Internal Control – Integrated Framework (2013 framework) issued by Committee of Sponsoring Organizations, our management concluded that our internal control over financial reporting was effective as of December 31, 2014 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Changes in Internal Control over Financial Reporting

    There were no changes in our internal control over financial reporting that occurred during the fourth quarter ended December 31, 2014, that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B.    OTHER INFORMATION

    On March 23, 2015, we entered into an unsecured $1.21 billion syndicated credit agreement with thirteen lenders, including National Rural Utilities Cooperative Finance Corporation, as administrative agent. This credit agreement replaced our $1.265 billion syndicated credit agreement. This credit agreement can be used to (a) advance funds for working capital purposes, (b) issue letters of credit thereunder and (c) support the issuance of up to $1.0 billion of commercial paper. This credit agreement has a maturity date of March 23, 2020, unless extended as provided therein.

    Loans under the credit agreement are subject to customary conditions to borrowing and may be (1) eurodollar rate loans, which shall bear interest at the London Interbank Offered Rate multiplied by the statutory reserve rate plus the applicable rate for eurodollar rate loans (ranging from .875% to 1.75% depending on our credit ratings) or (2) base rate loans or swing line loans, which shall each bear interest at a rate per annum equal to the greatest of (a) the prime rate, (b) the Federal funds rate plus .50%, and (c) the eurodollar rate for a one-month interest period plus 1.0%, plus the applicable rate for base rate loans (ranging from 0% to .75% depending on our credit ratings). We are also paying customary unused commitment fees, an administrative agent fee and letter of credit fees.

    The credit agreement contains customary representations, warranties, covenants, events of default and acceleration, including financial covenants to (a) maintain patronage capital of at least $675 million, (b) set rates reasonably expected to yield a margins for interest ratio of 1.10 and (c) limit our secured indebtedness and unsecured indebtedness, both as defined by the credit agreement, to $12.0 billion and $4.0 billion, respectively.

    The foregoing is a summary of certain terms of the credit agreement, is neither complete nor inclusive of all material terms of the credit agreement and is subject to, and qualified in its entirety by, the full text of the credit agreement, which is filed as Exhibit 10.13 to this annual report. For additional discussion of our liquidity program, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Sources of Capital and Liquidity—Liquidity."

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PART III

ITEM 10.    DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Our Board of Directors

Structure of our Board of Directors

    Our members elect our board of directors. Our board of directors consists of directors and general managers from our members, referred to as "member directors," and up to two outside directors. Our bylaws divide member director positions among the member scheduling groups specifically described in the bylaws, referred to as the "member groups." There are currently five member groups and, except for Group 5, each member group is represented by two member directors. Of each member group's two directors, one must be a general manager of a member in that member group and one must be a director of a member in that member group. Jackson Electric Membership Corporation is the only member in Group 5 and has only one director. The bylaws permit expansion of the number of member groups and changes in the composition of member groups. Formation of new member groups and changes in the composition of member groups are subject to certain required member approvals, and the requirement that the composition of the member groups at Oglethorpe, Georgia Transmission and Georgia System Operations be identical, except in cases where a member is no longer a member of one or more of Oglethorpe, Georgia Transmission or Georgia System Operations. The number of member director positions will change if additional member groups are formed or a member group ceases to exist. The bylaws also provide for three at-large member director positions which must each be filled by a director of one of our members.

    In an effort to provide for equitable representation among the member groups across the boards of directors of Oglethorpe, Georgia Transmission and Georgia System Operations, the bylaws provide for certain limitations on the eligibility of directors of members of each member group to fill the three at-large member director positions. No more than one at-large member director position on our board of directors may be filled by a director of a member of any member group, no more than two directors from members of any member group may be serving in at-large member director positions on the boards of directors of Oglethorpe, Georgia Transmission and Georgia System Operations, and at least one at-large member director position on the boards of directors of Oglethorpe, Georgia Transmission or Georgia System Operations must be filled by a director of a member of each member group that has at least two members.

    Pursuant to the bylaws, a member may not have both its general manager and one of its directors serve as a director of ours at the same time. Subject to a limited exception for Jackson Electric Membership Corporation, which is the sole member of one of the member groups, the bylaws prohibit any person from simultaneously serving as a director of Oglethorpe and either Georgia Transmission or Georgia System Operations.

    Our bylaws require outside directors to have experience related to our business, including, without limitation, operations, marketing, finance or legal matters. No outside director may be one of our current or former officers, a current employee of ours or a former employee of ours receiving compensation for prior services. Outside directors cannot also be a director, officer or employee of Georgia Transmission, Georgia System Operations or any member. Additionally, no person who receives payment from us in any capacity other than as an outside director, including direct or indirect payments for goods and services, may serve as outside director.

    The members of our board of directors serve staggered three-year terms.

Election of our Board of Directors

    For a cooperative organization to maintain its status under federal tax law, it must abide by the cooperative principle of democratic control. The nomination and election of the members of our board of directors and the representation of our members by the elected directors is consistent with this principle.

    Candidates for our board of directors must be nominated by the nominating committee. The nominating committee is comprised of one representative from each of our members. A majority vote of the nominating committee is required to nominate each candidate for the board of directors. Each member representative's nomination vote is weighted based on the number of retail customers

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served by the member. After the nominating committee nominates a candidate for a director position, the candidate must be elected by a majority vote of all of our member representatives, voting on an unweighted, one-member, one-vote basis. If the nominated candidate fails to receive a majority of the vote, the nominating committee must nominate another candidate and the member representatives will vote on that. Should that candidate also fail to receive a majority vote, this nomination and election process would be repeated until a nominated candidate is elected by a majority of the members.

    Potential candidates for our board of directors must meet the requirements set forth in our bylaws, as discussed under "– Structure of our Board of Directors." Management does not have a direct role in the nomination or election of the members of our board of directors.

    Neither we, the nominating committee, nor any of our members, to our knowledge, have a policy with regard to the consideration of diversity in identifying potential candidates for our board of directors.

Board of Directors Leadership Structure

    Our principal executive officer and chairman of the board positions are separate and are held by different persons. The chairman of the board and any vice-chairman of the board are elected annually by a majority vote of the members of our board of directors. Our president and chief executive officer is appointed by our board of directors. None of our executive officers nor any of our other employees are members of our board of directors.

    As a cooperative, our members are our owners. Our members believe that the most effective structure to efficiently provide for their current and future needs is to take a prominent role in the direction of our business. Member control over the board of directors, and the board of directors' independence from management is beneficial and provides for member input. Direct accountability to and separation from the board of directors helps insure that management acts in the best interests of our members.

Executive Officer and Director Biographies

    Our executive officers and directors are as follows:

Executive Officers

Overview

    We are managed and operated under the direction of a president and chief executive officer who is appointed by our board of directors. Our president and chief executive officer selects the remainder of the executive team. Each of our executive officers has entered into an employment contract with us that provides for minimum annual base salary and performance pay. See "EXECUTIVE COMPENSATION – Compensation Discussion and Analysis – Employment Agreements" for further discussion of these agreements.

Executive Officer Biographies

    Michael L. Smith is our President and Chief Executive Officer and has served in that capacity since November 2013. Prior to joining Oglethorpe, Mr. Smith served as Georgia Transmission's President and Chief Executive Officer from 2005 to 2013 after he joined Georgia Transmission as its Senior Vice President and Chief Financial Officer in 2003. From 2002 to 2003, Mr. Smith co-founded and served as the Executive Director of the Committee of Chief Risk Officers. From 1997 to 2002, Mr. Smith held multiple positions at Mirant Corporation, most recently as Vice President and

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Global Risk Officer. From 1994 to 1997, he was Manager of Planning and Evaluation for Vastar Resources and prior to that he worked at ARCO in various positions from 1983 to 1994. Mr. Smith has a Bachelor's degree in Business Law and a Masters of Business Administration in Finance from Louisiana State University. Mr. Smith is on the board of directors for SERC Reliability Corporation and also serves as a cooperative representative to the NERC Member Representative Committee. Mr. Smith is also on the board of directors of the Georgia Chamber of Commerce and for ACES Power Marketing.

    Michael W. Price is our Executive Vice President and Chief Operating Officer and has served in that office since February 1, 2000. In October 2008, Mr. Price's title changed from Chief Operating Officer to his current title. Mr. Price was employed by Georgia System Operations from January 1999 to January 2000, first as Senior Vice President and then as Chief Operating Officer. He served as Vice President of System Planning and Construction of Georgia Transmission from May 1997 to December 1998. He served as a manager of system control of Georgia System Operations from January to May 1997. From 1986 to 1997, Mr. Price was employed by Oglethorpe in the areas of control room operations, system planning, construction and engineering, and energy management systems. Prior to joining Oglethorpe, he was a field test engineer with the Tennessee Valley Authority from 1983 to 1986. Mr. Price has a Bachelor of Science degree in Electrical Engineering from Auburn University. Mr. Price is on the board of directors for SERC Reliability Corporation and ACES Power Marketing and a former director for the National Renewables Cooperative Organization. He is also a member of the Research Advisory Committee of the Electric Power Research Institute.

    Elizabeth B. Higgins is our Executive Vice President and Chief Financial Officer and has served in that office since July 2004. In October 2008, Ms. Higgins' title changed from Chief Financial Officer to her current title. Ms. Higgins served as Senior Vice President, Finance & Planning of Oglethorpe from July 2003 to July 2004. Ms. Higgins served as Vice President of Oglethorpe with various responsibilities including strategic planning, rates, analysis and member relations from September 2000 to July 2003. Ms. Higgins served as the Vice President and Assistant to the Chief Executive Officer of Oglethorpe from October 1999 to September 2000 and served in other capacities for Oglethorpe from April 1997 to September 1999. Prior to that, Ms. Higgins served as Project Manager at Southern Engineering from October 1995 to April 1997, as Senior Consultant at Deloitte & Touche, LLP from April 1995 to October 1995, and as Senior Consultant at Energy Management Associates from June 1991 to April 1995. Ms. Higgins has a Bachelor of Industrial Engineering degree from the Georgia Institute of Technology with high honors and a Master of Business Administration degree from Georgia State University.

    William F. Ussery is our Executive Vice President, Member and External Relations and has served in that office since October 2005. In October 2008, Mr. Ussery's title changed from Senior Vice President, Member and External Relations to his current title. Mr. Ussery previously served as Vice President and Assistant Chief Operating Officer of Oglethorpe from November 2003 to October 2005. Prior to joining Oglethorpe in 2001, Mr. Ussery held several key positions, including Chief Operating Officer, Vice President of Engineering and System Engineer at Sawnee Electric Membership Corporation. Mr. Ussery holds a Bachelor of Science degree in Electrical Engineering from Auburn University and an associate degree in Science from Middle Georgia College. Mr. Ussery is on the board of directors for the National Renewables Cooperative Organization. Since March 2007, Mr. Ussery has served as a board member of the Council on Alcohol and Drug, Inc. and previously served as Chairman of the Board.

    W. Clayton Robbins is our Senior Vice President, Governmental Affairs and has served in the office since October 2008. Prior to that Mr. Robbins was Senior Vice President, Government Relations and Chief Administrative Officer from July 2006 until October 2008, and as Chief Administrative Officer from January 2006 until July 2006. He also served as Senior Vice President, Administration and Risk Management of Oglethorpe from October 2002 to December 2006; and served as Senior Vice President, Finance and Administration of Oglethorpe from November 1999 to September 2002. Mr. Robbins served as Senior Vice President and General Manager of Intellisource, Inc. from February 1997 to October 1999. Prior to that, Mr. Robbins held several senior management and executive management positions at Oglethorpe beginning in 1986. Before joining Oglethorpe, Mr. Robbins spent 18 years with Stearns-Catalytic

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World Corporation, a major engineering and construction firm, including 13 years in management positions responsible for human resources, information systems, contracts, insurance, accounting, and project development. Mr. Robbins has a Bachelor of Arts degree in Business Administration from the University of North Carolina at Charlotte. Mr. Robbins serves as our director for the American Coalition for Clean Coal Electricity.

    Charles W. Whitney is our Senior Vice President and General Counsel and has served in that capacity since August 2009. Mr. Whitney has legal experience that spans a broad range of activities in both private practice and as chief counsel to a nuclear generating plant project. He has represented independent power producers and engineering, procurement and construction contractors in the development, construction and operation of power projects in Georgia, New York, Pennsylvania, Ohio, Michigan and Wisconsin. In private practice, Mr. Whitney's areas of focus were energy, particularly nuclear energy, regulatory, construction and labor law. His practice has also included extensive work in labor and employment discrimination; certification, enforcement and rate-making proceedings before state and federal regulators; and general trial work. In addition to practicing law for 25 years, Mr. Whitney has more than ten years of experience in senior management in the electricity industry, including both the regulated and unregulated aspects of the business. Mr. Whitney is a graduate of Wright State University and earned his Juris Doctor degree from Case Western Reserve University School of Law.

    Jami G. Reusch is our Vice President, Human Resources and has served in that office since July 2004. Ms. Reusch served as Oglethorpe's Director of Human Resources and held several other management and staff positions in Human Resources prior to July 2004. Prior to joining Oglethorpe in 1994, Ms. Reusch was a senior officer in the banking industry in Georgia, where she held various leadership roles. Ms. Reusch has a Bachelor of Education degree and a Master of Human Resource Development degree from Georgia State University. She also has a Senior Professional in Human Resources certification.

Board of Directors

Director Qualifications

    As required by our bylaws, all of the members of our board of directors, except for the outside director, are either directors or general managers of one of our members. This prerequisite helps to insure that the members of our board of directors have business experience related to electric membership corporations as well as an interest in the successful operation of our business. The members of our board of directors are elected solely by the vote of our members; neither we nor our management has any direct role in the nomination of the candidates or the election of members to our board of directors. Therefore, the following director biographies do not include a discussion of the specific experience, qualifications, attributes or skills that led our members to the conclusion that a person should serve as a director on our board of directors. For further discussion of our nomination and election process, see "– Our Board of Directors – Election of our Board of Directors."

Director Biographies

    C. Hill Bentley is a member group director (Group 3). Mr. Bentley has served on our board of directors since March 2004, and his present term will expire in March 2016. He is also a member of the audit committee. He is the Chief Executive Officer of Tri-County Electric Membership Corporation. He is on the Board of Directors of the Georgia Cooperative Council and a member of the board of directors of the Central Georgia Technical College Foundation. Mr. Bentley is a member of the Georgia Chamber of Commerce and is past President of the Jones County Chamber of Commerce. He serves on the Executive Committee and Territorial Integrity Fund Committee for Georgia Electric Membership Corporation. Mr. Bentley is a member, and a past President, of the Georgia Rural Electric Managers Association and past chair of the Rural Electric Management Development Council. He was also appointed by the Governor to serve a second term as a member of the Middle Georgia Regional Commission Council.

    Benny W. Denham is the Chairman of the Board and an at-large director. Mr. Denham has served on our board of directors since December 1988, and his present term will expire in March 2016. Mr. Denham has been co-owner of Denham Farms in Turner County, Georgia

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since 1980. Mr. Denham is a director of Irwin Electric Membership Corporation and a director of Georgia Electric Membership Corporation.

    Wm. Ronald Duffey is an outside director. Mr. Duffey has served on our board of directors since March 1997, and his present term will expire in March 2015. He is also the chairman of the audit committee and served as special liaison between senior management and the board during the search for a successor president and chief executive officer from June to November 2013. Mr. Duffey is the retired Chairman of the Board of Directors of Peachtree National Bank in Peachtree City, Georgia, a wholly owned subsidiary of Synovus Financial Corp. Prior to his employment in 1985 with Peachtree National Bank, Mr. Duffey served as Executive Vice President and Member of the Board of Directors for First National Bank in Newnan, Georgia. He holds a Bachelor of Business Administration degree from Georgia State College with a concentration in finance and has completed banking courses at the School of Banking of the South, Louisiana State University, the American Bankers Association School of Bank Investments, and The Stonier Graduate School of Banking, Rutgers University. Mr. Duffey is a director of Piedmont-Newnan Hospital and of Piedmont Healthcare, where he is chair of the audit and compliance committee and also serves on the executive committee. Mr. Duffey is also a member of the board of directors of the Georgia Chamber of Commerce.

    M. Anthony Ham is a member group director (Group 3). Mr. Ham has served on our board of directors since March 2004, and his present term will expire in March 2017. He is also a member of the compensation committee. Mr. Ham operates Tony Ham Elite Property Services. In December 2008, Mr. Ham left his position as the Clerk of the Superior and Juvenile Court in Brantley County, Georgia after 20 years of service. He has served as a director of Okefenoke Rural Electric Membership Corporation since 1994 and was appointed Secretary and Treasurer in 2007.

    Ernest A. "Chip" Jakins III is a member group director (Group 5). Mr. Jakins has served on our board of directors since 2014, and his present term will expire in March 2015. Mr. Jakins is a member of the construction project committee. Mr. Jakins is currently the President and Chief Executive Officer of Jackson Electric Membership Corporation and was previously President and Chief Executive Officer of Carroll Electric Membership Corporation. He is a member of the board of directors of the University of West Georgia Foundation, West Georgia Technical College and Carroll County Sertoma Club. He is also a member of the Carrollton Rotary Club, Carroll County Chamber of Commerce and Georgia Chamber of Commerce. He also serves as a director for Georgia System Operations, for Georgia EMC where he is a member of the Executive Committee, Economic Development Committee and Workers Compensation Fund Executive Committee, and for Green Power EMC.

    Fred A. McWhorter is a member group director (Group 4). Mr. McWhorter has served on our board of directors since September 2012, and his present term will expire in March 2016. He is a member of the construction project committee. Mr. McWhorter serves as Vice Chairman of the Rayle Electric Membership Corporation board of directors. Mr. McWhorter also serves on the board of directors for Georgia Electric Cooperative. He works for the U.S. Postal Service and is owner of F.A. McWhorter Poultry Farms.

    Marshall S. Millwood is the Vice-Chairman of the Board and an at-large director. Mr. Millwood has served on our board of directors since March 2003, and his present term will expire in March 2015. He is also the chairman of the compensation committee. He has been the owner and operator of Marjomil Inc., a poultry and cattle farm in Forsyth County, Georgia, since 1998. He is a director of Sawnee Electric Membership Corporation.

    Jeffrey W. Murphy is a member group director (Group 4). Mr. Murphy has served on our board of directors since March 2004, and his present term will expire in March 2015. He is also a member of the audit committee. Mr. Murphy has been the President and Chief Executive Officer of Hart Electric Membership Corporation since May 2002. He is also the Secretary of the Georgia Energy Cooperative.

    Danny L. Nichols is a member group director (Group 2). Mr. Nichols has served on our board of directors since March 2011, and his present term will expire in March 2017. Mr. Nichols is the chairman of the construction project committee. Mr. Nichols is the General Manager of Colquitt Electric Membership Corporation.

    Sammy G. Simonton is a member group director (Group 2). Mr. Simonton has served on our board of

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directors since October 2012, and his present term will expire in March 2015. He is also a member of the compensation committee. Mr. Simonton is a director of Walton Electric Membership Corporation. Mr. Simonton is currently the owner of Simonton Farms and has previous business affiliations with Meridian Homes, Moreland Altobelli Associates, Inc. and the Georgia Department of Transportation.

    Bobby C. Smith, Jr. is an at-large director. Mr. Smith has served on our board of directors since May 2008, and his present term will expire in March 2017. He is also a member of the construction project committee. Mr. Smith is a farmer. He is a member of the board of directors of Planters Electric Membership Corporation. He also serves on the board of directors for Georgia EMC and is Chairman of the board of the Screven County Development Authority and a member of the Sylvania Lions Club.

    George L. Weaver is a member group director (Group 1). Mr. Weaver has served on our board of directors since March 2010, and his present term will expire in March 2016. He is a member of the compensation committee. Mr. Weaver has been employed by Central Georgia Electric Membership Corporation since 1970 and is currently serving as President. Mr. Weaver is currently a director of Southeastern Data Cooperative and is a former director of Federated Rural Electric Insurance Corporation.

    James I. White is a member group director (Group 1). Mr. White has served on our board of directors since March 2012, and his present term will expire in March 2017. He is a member of the audit committee. Mr. White has served as a director of Snapping Shoals Electric Membership Corporation since 1995. Mr. White is the owner and president of Realty South Inc. and the owner of T.K. White Real Estate Co. and is a member of the Metro South Association of Realtors and Georgia Association of Realtors. Mr. White is also a member of the Henry County Chamber of Commerce and was involved with the Henry County Development Authority for over 20 years. He was previously vice president at the First National Bank in Crestview, Florida.

Committees of the Board of Directors

    Our board of directors has established an audit committee, a compensation committee and a construction project committee. The audit committee, the compensation committee and the construction project committee each operate pursuant to a committee charter and/or policy. We do not have a nominating and corporate governance committee; directors are nominated by representatives from each member whose weighted nomination is based on the number of retail customers served by each member, and after nomination, elected by a majority vote of the members, voting on a one-member, one-vote basis.

    Audit Committee.    The audit committee is responsible for assisting the board of directors in its oversight of various aspects of our business, including all material aspects of our financial reporting functions as well as risk assessment and management. Its responsibilities related to financial reporting include selecting our independent accountants, reviewing the plans, scope and results of the audit engagement with our independent accountants, reviewing the independence of our independent accountants and reviewing the adequacy of our internal accounting controls. The audit committee also reviews our policy standards and guidelines for risk assessment and risk management as discussed further under "– Board of Directors' Role in Risk Oversight." The members of the audit committee are currently Ronald Duffey, Jeffrey Murphy, Hill Bentley and James White. Mr. Duffey is the chairman of the audit committee. The board of directors has determined that Mr. Duffey qualifies as an independent audit committee financial expert.

    Compensation Committee.    The compensation committee is responsible for monitoring adherence with our compensation programs and recommending changes to our compensation programs as needed. Currently, the members of the compensation committee are Marshall Millwood, Anthony Ham, Sammy Simonton and George Weaver. Mr. Millwood is the chairman of the compensation committee.

    Construction Project Committee.    The construction project committee is responsible for reviewing and making recommendations to our board of directors with regards to major actions or commitments relating to new power plant construction projects and certain existing plant modification projects. Its responsibilities include reviewing and recommending to our board of directors final plant sites, project budgets (including certain modifications to project budgets) and project construction plans, and a quarterly reviewing of and reporting on the status of projects. The members of the

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construction project committee are currently Danny Nichols, Chip Jakins, Fred McWhorter, and Bobby Smith. Mr. Nichols is the chairman of the construction project committee.

Board of Directors' Role in Risk Oversight

    Our board of directors and the audit committee both actively oversee our exposure to risks in our business. Our board of directors has adopted corporate policies regarding management of risks related to financial management, capital investment and the use of derivatives. One of the primary risk oversight activities of the board of directors is to hold an annual strategic planning session to review potentially material threats and opportunities to our business. To facilitate this review, management develops a comprehensive strategic issues matrix. The strategic issues matrix identifies, describes, assesses and classifies the potential impact or magnitude, and outlines corporate strategies for addressing, potentially material threats and opportunities to our business. During this session, our board of directors reviews these analyses and affirms or assists management with developing strategies to address these strategic risks and opportunities. Additionally, management also develops and typically shares a corporate risk map with our audit committee. The corporate risk map depicts the probability of occurrence and the potential severity for each significant corporate risk.

    At each regular meeting of the board of directors, management provides the board with reports on significant changes related to the top strategic risks and opportunities facing us and a revised version of the strategic issues matrix that highlights any revisions to the matrix. The audit committee chairman also provides the board of directors with updates on overall corporate risk exposure. Furthermore, the board of directors receives risk analysis reports that identify key risks that could create variances from our approved annual budget and long-range forecasts and as well as discussing the potential likelihood and magnitude of changes to member rates related to these risks based on scenario modeling.

    Our board of directors has delegated direct oversight of corporate risk management and compliance to the audit committee. Pursuant to its charter, the audit committee reviews our business risk management process, including the adequacy of our overall control environment, in selected areas that represent significant financial and business risks. The audit committee receives regular reports on the activities of the risk management and compliance committee, which are described below, as well as quarter-end reports, which include changes to derivative hedge positions and overall corporate risk exposure. Additionally, the audit committee provides oversight over corporate ethics and compliance matters and receives regular reports on compliance, which include, but are not limited to, the review of i) significant compliance issues, ii) significant audits/examinations by governmental or other regulatory agencies, and iii) significant regulatory proceedings. The risk management and compliance committee, comprised of our chief executive officer, chief operating officer, chief financial officer, and the executive vice president of member and external relations, provides general oversight over all of our risk management and compliance activities, including but not limited to commodity trading, fuels management, insurance procurement, debt management, investment portfolio management, environmental and electric reliability compliance and cyber-security. The risk management and compliance committee has implemented comprehensive policies and procedures, consistent with current board policies, which govern our activities pertaining to market, compliance/regulatory and other risks. For further discussion about our risk management and compliance committee and its activities, see "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK."

Code of Ethics and Code of Conduct

    We have adopted a Code of Conduct that applies to all our employees, including our principal executive, financial and accounting officers. Our Code of Conduct is available at our website, www.opc.com.

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ITEM 11.    EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

Executive Summary

    The philosophy and objective of our compensation and benefits program is to establish and maintain competitive total compensation programs that will attract, motivate and retain the qualified skilled workforce necessary for our continued success. The compensation committee of the board of directors has the primary responsibility for establishing, implementing and monitoring adherence with our compensation programs. To help align executive officers' interests with those of our members, we have designed a significant portion of our cash compensation program as a pay for performance based system that rewards executive officers based on our success in achieving the corporate goals discussed below. To remain competitive, we review our total compensation program against generally available market data to gain a general understanding of current compensation practices.

Components of Total Compensation

    The compensation committee determined that compensation packages for the fiscal year ended December 31, 2014 for our executive officers should be comprised of the following three primary components:

•

Annual base salary,

•

Performance pay, which consists of a cash award based on the achievement of corporate goals, and

•

Benefits, which consist primarily of health, welfare and retirement benefits.

    Each of our executive officers has an employment agreement that provides for minimum annual base salary and performance pay. See "– Employment Agreements."

    Since we are an electric cooperative, we do not have any stock and as a result do not have equity-based compensation programs.

    Base Salary.    Base salary is the primary component of our compensation program and it is set at a level to attract and retain executives who can lead us in meeting our corporate goals. Base salary levels are set based on several factors, including but not limited to the position's duties and responsibilities, the individual's value and contributions to the company, work experience and length of service.

    Performance Pay.    Performance pay is designed to reward executive officers based on the achievement of certain strategic corporate goals. The corporate goals selected are designed to align the interests of our executive team and employees with the interests of our members. The compensation committee believes it is appropriate to consider only corporate goal achievement when determining executive officers' performance pay because our corporate philosophy focuses on teamwork, and we believe that better results evolve from mutual work towards common goals. Furthermore, the compensation committee believes that our achievement of these corporate goals will correspond to high company performance, and our executive officers are responsible for directing the work and making the strategic decisions necessary to successfully meet these goals. Each executive officer is eligible to receive up to 20% of his or her base salary as a performance bonus based entirely on the achievement of corporate goals.

    Importantly, our executive officers cannot help us meet our goals and improve performance without the work of others. For this reason, the performance goals set at the corporate level are the same for both executive officers and non-executive employees.

    Benefits.    The benefits program is designed to allow executive officers to choose the benefit options that best meet their needs. Our president and chief executive officer recommends changes to the benefits program or level of benefits that all executive officers, including our president and chief executive officer, receive to the compensation committee. The compensation committee then reviews and recommends changes to the board of directors for its approval. To meet the health and welfare needs of our executive officers at a reasonable cost, we pay for 80-85% of an executive officer's health and welfare benefits. Our president and chief executive officer decides our exact cost sharing percentage. We also provide each executive officer with life insurance coverage of two times the officer's base salary, up to $800,000, as well as disability insurance at a level equal to 60% of the officer's base salary. The health, life and disability insurance coverage we provide to our executive officers is consistent with the coverage we provide to our employees generally.

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    We also provide retirement benefits that allow executive officers the opportunity to develop an investment strategy that best meets their retirement needs. We will contribute up to $0.75 of every dollar an executive officer contributes to his or her retirement plan, up to 6% of an executive officer's pay per period, and will contribute an additional amount equal to 8% of an executive officer's pay per period. See "– Nonqualified Deferred Compensation" below for additional information regarding our contributions to our executive officers' retirement plans.

    Perquisites.    We provide our executive officers with perquisites that we and the compensation committee believe are reasonable and consistent with our overall compensation program. The most significant perquisite provided to our executive officers is a monthly car allowance, the amount of which is based upon the executive officer's position. Our president and chief executive officer approves the executive officers eligible for car allowances and reports this information to the compensation committee. The car allowance for our president and chief executive officer is included in his employment agreement. The compensation committee periodically reviews the levels of perquisites provided to executive officers.

    Bonuses.    Our practice has been to, on infrequent occasions, award cash bonuses to senior management related to exemplary performance. Our compensation committee may determine bonus criteria and may recommend to our board of directors for approval of discretionary bonuses to members of our senior management team. Our president and chief executive officer may determine bonus criteria and issue discretionary bonuses to other members of senior management.

Establishing Compensation Levels

    Role of the Compensation Committee.    The compensation committee annually reviews each of the components of our compensation program for our officers, directors and employees and recommends any changes to our board of directors for approval. In order to have a compensation program that is internally consistent and equitable, the compensation committee considers several subjective and objective factors when determining the compensation program. The compensation committee currently reviews and sets the compensation for our president and chief executive officer. Some of the factors reviewed include the position's duties and responsibilities, the individual's job performance, experience, longevity of service and overall value provided for our members.

    The compensation committee also approves our performance pay program, including the corporate goals related to such program. Bonuses for the president and chief executive officer are also at the discretion of the compensation committee. The compensation committee receives a comprehensive report on an annual basis regarding all facets of our compensation program. The compensation committee also reviews the employment contracts each year and makes an affirmative decision whether they should be extended.

    The compensation committee operates pursuant to a statement of functions that sets forth the committee's objectives and responsibilities. The compensation committee's objective is to review and recommend to the board of directors for approval any changes to various compensation related matters, as well as any significant changes in benefits cost or level of benefits, for the members of the board of directors, the executive officers, and other employees. The compensation committee annually reviews the statement of functions and makes any necessary revisions to ensure its responsibilities are accurately stated.

    Role of Management.    Our president and chief executive officer is the key member of management involved in our compensation process. He annually reviews the compensation of our other executive officers and in certain circumstances provides an upward adjustment to the executive officers' base salary. Our president and chief executive officer reports the executive officers' salaries to the compensation committee annually. Some of the factors the president and chief executive officer considers include the person's relative responsibilities and duties, experience, job performance, longevity of service and overall value provided for our members.

    Our president and chief executive officer, together with the other executive officers, identifies corporate performance objectives that are used to determine performance pay amounts. He and our vice president, human resources present these goals to the compensation committee. The compensation committee then reviews and approves the goals and presents them to the board of directors for final approval.

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    Role of the Board of Directors.    Our board of directors must approve changes recommended by the compensation committee. These approvals include the compensation of our president and chief executive officer and the components of our compensation program each year.

    Role of Generally Available Market Data.    To confirm that our compensation remains competitive, we review standardized surveys to compare our total compensation program against other companies in the utility industry of a similar size. We do not benchmark against such data; rather we utilize these surveys to gain a general understanding of current compensation practices and better understand and compare the components of our compensation program. The surveys we review are generally available, and we have not hired a compensation consultant to provide us with information on executive compensation data. Executive compensation levels at other companies do not drive our compensation decisions, and we do not target a specific market percentile for our executive officer compensation.

Corporate Goals for Performance Pay

    We choose to tie performance compensation to selected corporate goals that most appropriately measure our achievement of our strategic objectives. For 2014, our performance measures were divided into the following categories: i) safety, ii) operations, iii) project management, iv) corporate compliance v) financial, and vi) quality. Targeted performance measures in these categories are designed to help us accomplish our corporate goals which will benefit our members, employees and promote responsible environmental stewardship.

    The maximum performance pay each executive officer can receive is 20% of his or her salary and in order to receive the full 20%, 100% of the performance measures must be achieved. The performance measures are weighted to align with our current strategic focus, and each goal is reviewed annually, and adjusted in order to reflect any changes in our strategic focus. For example, in 2014, we added a new goal to assess our performance in the project management of the construction of Vogtle Units No. 3 and No. 4. We also review and refine these goals annually and make adjustments as necessary to ensure that we are consistently stretching our expectations and performance. Although some performance measures may stay the same, the applicable threshold may become more difficult. The following provides an overview of the purposes of each category of our corporate goals:

    Safety.    Our safety goals provide employees a financial incentive to focus on a safe workplace environment, which increases employee morale and minimizes lost time. One safety performance goal is measured by comparing the incident rate in our work environment against the national incident rate compiled by the U.S. Department of Labor's Bureau of Labor Statistics. Two other goals focus on our internal safety program and safety training and meetings.

    Operations.    The operations goals measure how well each of our operating plants responds to system requirements. In order to optimize generation for system load requirements, we generally dispatch the most efficient and economical generation resources first. If the preferred generation resource is not available when called upon, we must resort to a more expensive alternative. Most of the performance measures in this category, including start reliability and equivalent forced outage rate are measured against industry averages and the applicable thresholds are set above average. To meet these standards, we must operate and maintain these facilities in a manner which minimizes long-term maintenance and replacement energy costs. Certain operational goals take into account performance standards as required by contracts related to the facility operations. New in 2014, operations goals include performance measures related to our co-owned facilities operated by Georgia Power. Our achieving operational excellence at the corporate level results in the most reliable, efficient and lowest cost power supply for our members.

    Project Management.    Our project management goal relates to the Vogtle Units No. 3 and No. 4 construction project and how well we are managing the project in our role as a Co-owner. Performance measures include our participation on the Project Management Board, degree and effectiveness of oversight involvement, understanding of the project status and project issues, and timeliness and usefulness of project communications to our members and our board of directors. Our president and chief executive officer will assign a score based on his assessment of the overall effectiveness of our management of the project and

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submit the score to the construction committee of our board of directors for approval.

    Corporate Compliance.    Our corporate compliance goals are divided into two categories – environmental and electric reliability standards. The environmental goals promote our commitment to responsible environmental stewardship while providing reliable and affordable energy. We measure our performance by the number of environmental incidents, such as spills, which not only increase costs for our members but may cause environmental damage. Electric reliability standards compliance is measured by reviewing our performance as determined by standards set by the electric reliability organizations and through the development of a comprehensive cyber security program. To achieve the maximum awards for the environmental and reliability categories, we must avoid any spills or notices of violation and achieve internal program development goals.

    Financial.    Our financial goals provide direct benefits to our members by lowering power costs. Certain goals are tied to specific financial performance while others focus on emphasizing importance of appropriate and effective internal controls. For example, the cost savings goal is designed to encourage staff to identify and implement strategies that result in cost savings or cost reductions in either the current year or in the long-term. Any cost savings included in this goal must be over and above what would generally be expected. Two remaining financial goals focus on our internal control over financial reporting and the profitability of off-system sales from Smith.

    Quality.    Quality is a subjective goal that is intended to measure the satisfaction of our members with our efforts, initiatives, responsiveness and other intangibles that are not readily quantified. Performance on this goal is based on semi-annual surveys submitted by the members of the board of directors who, except for our outside director, are general managers or directors of our members. The results of the surveys are averaged to determine the total quality result. In order to achieve the maximum award, we must receive a 100% rating from every member of the board of directors on both surveys, an extremely high standard that has yet to be achieved.

Calculation of Performance Pay Earned

    Performance pay earned by our executive officers is based entirely on our success in achieving each of our corporate goals. Annually, our board of directors approves a weighted system for determining performance pay whereby we assign a percentage to each of the goals, as noted below. Based on the achievement of each performance metric, a percentage of the weighted goal is available as performance pay to our executive officers. Each performance metric has a minimum threshold level that must be achieved before any performance pay is earned. If the actual performance for that metric meets the applicable threshold, then a pre-determined percentage of the percentage pay for that metric will be awarded. The percentage awarded will increase up to a maximum of 100% of the weighted goal if the maximum performance level of the performance metric is achieved. Threshold and maximum levels are reviewed annually and generally reset to demand ever improving corporate performance. Meeting the applicable thresholds is not guaranteed and requires diligence and hard work. Exceptional performance is required to reach the maximum goals.

    For each executive officer, we multiply 20% of his or her base salary by the achievement percentage to determine his or her performance bonus. For example, if we had a 90% corporate goal achievement rate in a given year, each executive officer's performance bonus would equal (base salary × 20%) × (90%).

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Assessment of Performance of 2014 Corporate Goals

    The specific corporate performance measures, thresholds, maximums and results for our executive officers' 2014 performance pay were the following:

    As noted above, we achieved 89.21% of our corporate goals for 2014. As a result of achieving 89.21% of our corporate goals, each of our executive officers received performance pay in an amount equal to 89.21% of 20% of his or her base salary. Set forth below is a table showing performance pay figures for each of our executive officers who received performance pay in 2014:

Employment Agreements

General

    We have an employment agreement with each of our executive officers. We negotiated each of these employment agreements on an arms-length basis, and the compensation committee determined that the terms of each agreement are reasonable and necessary to ensure that our executive officers' goals are aligned with our members' interests and that each performs his or her respective role while acting in our members' best interests. The compensation committee reviews these agreements annually and last reviewed each employment agreement, in November 2014.

    We entered into an employment agreement with Mr. Smith on October 11, 2013. The current term of the

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agreement extends through December 31, 2017 and will automatically renew pursuant to the corresponding provision of the agreement for successive one-year periods unless either party provides written notice not to renew the agreement twenty-five months before the expiration of any extended term. No such notice has been provided. Mr. Smith's minimum annual base salary under his agreement is $630,000, and is subject to review and upward adjustment by our board of directors. Mr. Smith is eligible for an annual bonus and to participate in incentive compensation plans generally available to similarly situated employees, determined by our board of directors at its sole discretion. Mr. Smith is also entitled to an automobile or an automobile allowance during the term of the agreement. Mr. Smith's employment agreement contains severance pay provisions.

    We also have employment agreements with Mr. Price, Ms. Higgins, Mr. Ussery, and Mr. Whitney. Pursuant to the automatic renewal provisions of these employment agreements, the current term of each agreement extends through December 31, 2016 and will continue to automatically renew for successive one-year periods unless either party provides written notice not to renew the agreement thirteen months before the expiration of any extended term. No such notices have been provided.

    Minimum annual base salaries under these agreements are $255,116 for Mr. Price, $246,887 for Ms. Higgins, $171,700 for Mr. Ussery, and $300,000 for Mr. Whitney. Salaries are subject to review and possible upward adjustment as determined by the president and chief executive officer. Each executive is also eligible for an annual bonus and to participate in incentive compensation plans generally available to similarly situated employees, determined by us at our sole discretion. The employment agreements with Mr. Price, Ms. Higgins, Mr. Ussery and Mr. Whitney contain severance pay provisions.

Assessment of Severance Arrangements

    Pursuant to their respective employment agreements, each of our executive officers is entitled to certain severance payments and benefits in the event they are terminated not for cause or they resign for good reason.

    In determining that the president and chief executive officer's employment agreement was appropriate and necessary, the compensation committee considered Mr. Smith's role and responsibility within Oglethorpe in relation to the total amount of severance pay he would receive upon the occurrence of a severance event. The committee also considered whether the amount Mr. Smith would receive upon severance was appropriate given his total annual compensation. Upon review, the compensation committee determined that a maximum amount of severance compensation equal to a maximum of two year's compensation, plus benefits as described below, was an appropriate amount of severance compensation for Mr. Smith. The compensation committee believes that entering into a severance agreement with our president and chief executive officer is beneficial because it gives us a measure of stability in this position while affording us the flexibility to change management with minimal disruption, should our board of directors ever determine such a change to be necessary and in our best interests. The compensation committee considers an amount equal to up to two years of compensation and benefits to be an appropriate amount to address competitive concerns and offset any potential risk Mr. Smith faces in his role as our president and chief executive officer. Furthermore, it should be noted that we do not compensate our president and chief executive officer using options or other forms of equity compensation that typically lead to significant wealth accumulation.

    Pursuant to the terms of his employment agreement, Mr. Smith will be entitled to a lump-sum severance payment upon the occurrence of any of the following events: (1) we terminate his employment without cause; or (2) he resigns due to a demotion or material reduction of his position or responsibilities, a material reduction of his base salary, or a relocation of his principal office by more than 50 miles. The severance payment will equal Mr. Smith's then current base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), and is payable within 30 days of termination, subject to the provisions of Internal Revenue Code Section 409A. In addition, Mr. Smith will be entitled to outplacement services and an amount equal to his costs for medical and dental continuation coverage under COBRA, each for the longer of one year or the remaining term of the agreement. Severance is payable only if Mr. Smith signs a form releasing all claims against us within 20 days after his termination date. The maximum severance that would be payable to Mr. Smith in the circumstances described above is $1,422,235.

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    The compensation committee also considered the total amount of compensation each of the other executive officers would receive upon the occurrence of a severance event. The compensation committee determined that it was appropriate for our other executive officers to receive severance compensation equal to one year's compensation, plus benefits as described below, because such agreements provide a measure of stability for both us and our other executive officers. In addition, like our president and chief executive officer, our other executive officers are not compensated using options or other forms of equity compensation that lead to significant wealth accumulation. Therefore, the compensation committee believes such severance compensation is necessary to address competitive concerns and offset any potential risk our executive officers face in the course of their employment.

    Pursuant to the terms of their employment agreements, Mr. Price, Ms. Higgins, Mr. Ussery and Mr. Whitney will each be entitled to a lump-sum severance payment if we terminate the executive without cause or if the executive resigns after a demotion or material reduction of his or her position or responsibilities, a reduction of his or her base salary, or a relocation of his or her principal office by more than 50 miles. The severance payment will equal one year of the executive's then current base salary, payable six months after the executive's termination date. In addition, the executive will be entitled to six months of outplacement services and an amount equal to the executive's cost for medical and dental continuation coverage under COBRA for six months. Severance is payable only if the executive signs a form releasing all claims against us within 45 days after his or her termination date. The maximum severance that would be payable to Mr. Price, Ms. Higgins, Mr. Ussery and Mr. Whitney in the circumstances described above is $426,691, $429,888, $331,889 and $373,001, respectively.

Compensation Committee Report

    The Compensation Committee of Oglethorpe Power Corporation has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2014 for filing with the SEC.

Respectfully Submitted,
The Compensation Committee

M. Anthony Ham
Marshall S. Millwood
Sammy G. Simonton
George L. Weaver

Compensation Committee Interlocks and Insider Participation

    Marshall S. Millwood, M. Anthony Ham, Sammy G. Simonton and George L. Weaver served as members of our compensation committee in 2014.

    Mr. Weaver is a director of ours and also the president of Central Georgia Electric Membership Corporation. Central Georgia is a member of ours and has a wholesale power contract with us. Central Georgia's payments of $33.9 million to us in 2014 under its wholesale power contract accounted for 2.4% of our total revenues.

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Summary Compensation Table

    The following table sets forth the total compensation paid or earned by each of our executive officers for the fiscal years ended December 31, 2014, 2013 and 2012.

(1)

Figures for 2014 consist of matching contributions and contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, and Mr. Whitney of $32,500, $32,500, $32,293, $30,217, and $31,895, respectively; contributions by Oglethorpe to a nonqualified deferred compensation plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, and Mr. Whitney, respectively of $27,600, $15,132, $14,691, $7,132 and $9,777; car allowances; paid time off, executive health benefits; customary holiday gifts and service awards.

(2)

Mr. Smith became an Oglethorpe employee in November 2013.

    The following table sets forth the threshold and maximum awards available to the executive officers listed in the Summary Compensation Table who received performance pay for the fiscal year ended December 31, 2014.

    For an explanation of the criteria and formula used to determine the awards listed above, please refer to "– Compensation Discussion and Analysis – Assessment of Performance of 2014 Corporate Goals."

Nonqualified Deferred Compensation

    We maintain a Fidelity Non-Qualified Deferred Compensation Program for each of the executive officers in the table below. This non-qualified deferred compensation program serves as a vehicle through which we can continue our employer retirement contributions to our executive officers beyond the IRS salary limits on the retirement plan ($260,000 as indexed).

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    The following table sets forth contributions for the fiscal year ended December 31, 2014 along with aggregate earnings for the same period.

Compensation Policies and Practices As They Relate to Our Risk Management

We believe that our compensation policies and practices for all employees, including executive officers, do not create risks that are reasonably likely to have a material adverse effect on us.

Director Compensation

The following table sets forth the total compensation paid or earned by each of our directors for the fiscal year ended December 31, 2014.

    During 2014, we paid our member directors a fee of $1,200 per board meeting and $800 per day for attending committee meetings, other meetings, or other official business approved by the chairman of the board of directors. Member directors are paid $600 per day for attending the annual meeting of members and member advisory board meetings. Our outside director was paid a fee of $5,500 per board meeting for four meetings a year and a fee of $1,000 per board meeting for the remaining other board meetings held during the year. Our outside director was also paid $1,000 per day for attending committee meetings, annual meetings of the members or other official business. In addition, we reimburse all directors for out-of-pocket expenses incurred in attending a meeting. All directors are paid $100 per day when participating in meetings by conference call. The chairman of the board of directors is paid an additional 20% of his director's fee per board meeting for time involved in preparing for the meetings. The audit committee financial expert is paid an additional $400 per audit committee meeting for the time involved in fulfilling that role. Neither our outside director nor member directors receive any perquisites or other personal benefits from us.

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ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

    Not Applicable.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Transactions

    Hill Bentley is a director of ours and the Chief Executive Officer of Tri-County Electric Membership Corporation. Tri-County is a member of ours and has a wholesale power contract with us. Tri-County's revenues of $15.6 million to us in 2014 under its wholesale power contract accounted for approximately 1.1% of our total revenues.

    Chip Jakins is a director of ours and the President and Chief Executive Officer of Jackson Electric Membership Corporation. Randall Pugh was a director of ours and was the president and Chief Executive Officer of Jackson Membership Corporation through March 2014. Mr. Jakins succeeded Mr. Pugh in both positions. Jackson is a member of ours and has a wholesale power contract with us. Jackson's revenues of $146.1 million to us in 2014 under its wholesale power contract accounted for approximately 10.4% of our total revenues.

    Jeffrey Murphy is a director of ours and the President and Chief Executive Officer of Hart Electric Membership Corporation. Hart is a member of ours and has a wholesale power contract with us. Hart's revenues of $21.4 million to us in 2014 under its wholesale power contract accounted for approximately 1.5% of our total revenues.

    Danny Nichols is a director of ours and is the General Manager of Colquitt Electric Membership Corporation. Colquitt is a member of ours and has a wholesale power contract with us. Colquitt's revenues of $41.3 million to us in 2014 under its wholesale power contract accounted for approximately 2.9% of our total revenues.

    George Weaver is a director of ours and the President of Central Georgia Electric Membership Corporation. Central Georgia is a member of ours and has a wholesale power contract with us. Central Georgia's revenues of $33.9 million to us in 2014 under its wholesale power contract accounted for approximately 2.4% of our total revenues.

    We have a Standards of Conduct/Conflict of Interest policy that sets forth guidelines that our employees and directors must follow in order to avoid conflicts of interest, or any appearance of conflicts of interest, between an individual's personal interests and our interests. Pursuant to this policy, each employee and director must disclose any conflicts of interest, actions or relationships that might give rise to a conflict. Our president and chief executive officer is responsible for taking reasonable steps to ensure that the employees are complying with this policy and the audit committee is responsible for taking reasonable steps to ensure that the directors are complying with this policy. The audit committee is charged with monitoring compliance with this policy and making recommendations to the board of directors regarding this policy. Certain actions or relationships that might give rise to a conflict of interest are reviewed and approved by our board of directors.

Director Independence

    Because we are an electric cooperative, the members own and manage us. Our bylaws set forth specific requirements regarding the composition of our board of directors. See "DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE – Our Board of Directors – Structure of Our Board of Directors" for a detailed discussion of the specific requirements contained in our bylaws regarding the composition of our board of directors.

    In addition to meeting the requirements set forth in our bylaws, all directors, with the exception of Chip Jakins, satisfy the definition of director independence as prescribed by the NASDAQ Stock Market and otherwise meet the requirements set forth in our bylaws. Mr. Jakins does not qualify as an independent director because he is the President and Chief Executive Officer of Jackson, which accounted for approximately 10.4% of our revenues for the fiscal year ended December 31, 2014. Although we do not have any securities listed on the NASDAQ Stock Market, we have used its independence criteria in making this determination in accordance with applicable SEC rules.

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ITEM 14.    PRINCIPAL ACCOUNTANT FEES AND SERVICES

    For 2014 and 2013, fees for services provided by our independent registered public accounting firm, Ernst & Young LLP were as follows:

    In considering the nature of the services provided by our independent registered public accounting firm, the audit committee determined that such services are compatible with the provision of independent audit services. The audit committee discussed all non-audit services to be provided by independent registered public accounting firm to us with management prior to approving them to confirm that they were non-audit services permitted to be provided by our independent registered public accounting firm.

Pre-Approval Policy

    The audit and permissible non-audit services performed by Ernst & Young LLP in 2014 were pre-approved in accordance with the pre-approval policy and procedures adopted by the audit committee. The policy requires that requests for all services must be submitted to the audit committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings.

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PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    List of Documents Filed as a Part of This Report.

    Exhibits marked with an asterisk (*) are hereby incorporated by reference to exhibits previously filed by the Registrant as indicated in parentheses following the description of the exhibit.

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SIGNATURES

    Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of March, 2015.

    Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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