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 261 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 4.1 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 totals 7,747 megawatts of summer planning reserve capacity, which includes 712 megawatts of Smarr EMC assets that we manage and 1,240 megawatts at the Smith facility, which is currently being sold off-system. This generation portfolio includes units fueled 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 2013, two of our members, Cobb EMC and Jackson EMC, accounted for 13.2% and 10.9% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2013.

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 2013, we supplied energy that accounted for approximately 51% 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. The Rural Utilities Service and Department of Energy do have contractual approval rights over changes to the formulary rate under the wholesale power contracts. See "– Relationship with Federal Lenders." Currently, our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

First Mortgage Indenture

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

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

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our net margins (after certain defined adjustments), plus

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

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

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

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

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mortgage indenture, (ii) our equity as of the end of the 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, 2013, our equity ratio was 9.1%.

    As of December 31, 2013, we had approximately $6.2 billion of secured indebtedness outstanding under the first mortgage indenture. From time to time, we may issue additional first mortgage obligations ranking equally and ratably with the existing first mortgage indenture obligations. The aggregate principal amount of obligations that may be issued under the first mortgage indenture is not limited; however, our ability to issue additional obligations under the first mortgage indenture is subject to certain requirements related to the certified value of certain of our tangible property, repayment of obligations outstanding under the first mortgage indenture and payments made under certain pledged contracts relating to property to be acquired.

Relationship with Federal Lenders

Rural Utilities Service

    Historically, federal loan programs administered by the Rural Utilities Service, an agency of the United States Department of Agriculture, have provided the principal source of financing for electric cooperatives. Loans guaranteed by the Rural Utilities Service and made by the Federal Financing Bank have been a major source of funding for us. However, the availability and magnitude of Rural Utilities Service-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. The President's budget proposal for fiscal year 2014 provided for $4.0 billion in loans – a reduction of almost 40% from 2013 levels. Under the President's 2014 budget, not less than $3 billion would have been available 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. And not more than $1 billion would have been available for environmental improvements to fossil-fueled generation that would reduce emissions. However, Congress adopted a budget for 2014 that did not include any of these restrictions, with loan levels of $5 billion, considered sufficient to meet the current demand. Congress has also 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 will have to establish a process to implement this authorization prior to making it available to borrowers. The President's budget proposal for fiscal year 2015 provides for $5 billion in loans. Not less than $4 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 $1 billion could be made available for environmental improvements to fossil-fueled generation that would reduce emissions. Although Congress has historically rejected proposals to dramatically curtail 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. Currently, under the loan contract, the Rural Utilities Service has approval rights over certain significant actions and arrangements, 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,

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changes to plant ownership and operating agreements, and

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amounts of short-term debt outstanding exceeding 30% of our total utility plant through December 31, 2014 and 15% of total capitalization thereafter.

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    As of December 31, 2013, we had $2.7 billion of outstanding loans guaranteed by the Rural Utilities Service and secured under our first mortgage indenture.

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. Aggregate borrowings under the facility may not exceed $3.057 billion of eligible project costs.

    Under this loan guarantee agreement, the Department of Energy has approval rights over certain significant actions and arrangements, 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.

    In connection with the closing of this agreement, we made an initial advance of $725 million under this facility in February 2014 which is secured under our first mortgage indenture. For additional information on Vogtle Units No. 3 and No. 4, see "– 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 37 of 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 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,

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human resources, facility management, telecommunications and information technology at cost.

    As of December 31, 2013, we had approximately $9.4 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $3.0 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 712 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.

    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 among distributors or power suppliers; and

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other regulatory and business changes that may affect relative values of generation classes or have impacts on 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, certain legislative proposals have included various credits that would ultimately be phased out to offset the initial economic impact of regulation. 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, along with potential credits that could be available to us or our members under certain legislative proposals, would mitigate the impact, if any, on our and our members' competitiveness resulting from these legislative proposals, if enacted. See " REGULATION  – Environmental – Carbon Dioxide Emission and Climate Change  – Pending Legislation " 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.

    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.

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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 2013, we supplied approximately 51% of the retail energy requirements of our members.

Generating Plants

    Our fleet of generating units totals 7,747 megawatts of summer planning reserve capacity, including 712 megawatts of Smarr EMC assets that we manage and 1,240 megawatts at the Smith 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 2013, 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 the Thomas A. Smith Energy Facility 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

    We are participating in 30% of the cost of constructing two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4.

    In April 2008, Georgia Power, for itself and as agent for us, the Municipal Electric Authority of Georgia and the City of Dalton, the "Co-owners," signed an Engineering, Procurement and Construction Contract with Westinghouse Electric Company, LLC and Stone & Webster, Inc., together, the "Contractor." Pursuant to the contract, the Contractor will supply and construct two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology, with the exception of certain owner supplied items. Under the contract, 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,

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as well as adjustments for change orders and performance bonuses. Each Co-owner is severally, not jointly, liable to the Contractor based on its ownership share. The contract includes certain 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.

    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 of certain credit rating downgrades of any Co-owner, 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 contract 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 terminate the contract under certain circumstances, including certain Co-owner suspension or delays of work, action by a governmental authority to stop work permanently, certain breaches of the contract 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 level, and additional challenges are expected 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.

    Current litigation relates to costs associated with design changes to the DCD and costs associated with 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. In July 2012, the Co-owners and Contractor began negotiations regarding these costs, including the assertion by the Contractor that the Co-owners are responsible for these costs under the terms of the contract. 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 further schedule extensions. 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. 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 September 2013, the Contractor appealed the decision to the U.S. Court of Appeals for the District of Columbia. While litigation has commenced 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.

    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.

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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.

    The issues mentioned above, in addition to other factors that have materialized during the development and construction process, have caused revisions to the estimated project schedule and cost. The current estimated commercial operation dates for Units No. 3 and No. 4 are the fourth quarter of 2017 and 2018, respectively. Our current estimated project cost, including allowance for funds used during construction and a contingency amount, is approximately $4.5 billion. Commercial responsibility for the revised commercial operation dates and additional costs remain in dispute.

    As construction continues, the risk remains that additional challenges in the fabrication, assembly, delivery and installation of 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 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. These claims may be resolved through formal and informal dispute resolution procedures under the contract, but also may be resolved through litigation.

    As of December 31, 2013, our total investment in the additional Vogtle units was $2.1 billion. 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, and made an initial advance under this loan for $725 million. We have also issued approximately $1.4 billion of first mortgage bonds through the capital markets to provide long-term financing for a portion of these costs. We expect that we will finance any additional project costs in the capital markets, including any amounts not funded through the Department of Energy loan program. See " MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  – Financial Condition – Capital Requirements  – Capital Expenditures " and "–  Financing Activities. "

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

Other Future Power Resources

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

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    Our members serve approximately 1.8 million electric consumers (meters) representing approximately 4.1 million people. Our members serve a region covering approximately 38,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 151 of the State's 159 counties. Historically, our members' sales by customer class have been approximately two-thirds to residential consumers and slightly less than one-third to commercial and industrial consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. Each year we file 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 2011 through 2013, and also shows the amount of their energy requirements that we supplied. From 2011 through 2013, demand requirements of the members decreased at an average annual compound rate of 4.7% and energy requirements decreased at an average annual compound rate of 2.1%. 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 an 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 pressures faced by Congress.

    The President's budget proposal for fiscal year 2014 proposed to reduce funding by almost 40% from 2013 levels for the Rural Utilities Service electric program. The funding was proposed to be available only for renewable energy, generation with carbon sequestration projects and certain environmental improvements. However, Congress adopted a budget for 2014 that did not include these restrictions with loan levels of $5 billion, sufficient to meet the current demand. The President's budget proposal for fiscal year 2015 provides for loan levels of $5 billion. However, the funding is proposed to be available only for renewable energy, generation with carbon sequestration projects and certain environmental improvements. 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.

Members' Relationships with Georgia Transmission and Georgia System Operations

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

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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 2013, we supplied approximately 51% 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 satisfied 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 2013, 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 facilities owned by Smarr EMC purchase the output of those facilities pursuant to long-term, take-or-pay power purchase agreements. Smarr EMC owns Smarr Energy Facility, a two-unit, 222 megawatt gas-fired combustion turbine facility, and Sewell Creek Energy Facility, a four-unit, 490 megawatt gas-fired combustion turbine facility. Smarr Energy Facility began commercial operation in June 1999, and Sewell Creek Energy Facility began commercial operation in June 2000. We provide operations, financial and management services to Smarr EMC.

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.

Georgia Power Block Purchase

    Thirty members have entered into power supply contracts with Georgia Power under which they purchase an aggregate of 750 megawatts of capacity and associated energy. These contracts expire December 31, 2014.

Other Member Resources

    Our members obtain their remaining power supply requirements from various sources. Thirty-three members have entered into contracts with third parties

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for some or all of their incremental power requirements, with remaining terms ranging from 2 to 32 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.

    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 or are in the process of installing 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, or the purchase of emission allowances. Failure to comply with these requirements could result in civil and criminal penalties, and could include the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current and future environmental laws or regulations. Should we fail to be in compliance with these requirements, it would constitute a default under those debt instruments. 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 Congress have resulted in the enactment of legislation 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 following appear to be the most significant ongoing Clean Air Act-related actions.

    National Ambient Air Quality Standards and Nonattainment Updates.     The Clean Air Act requires the Environmental Protection Agency, or 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. Typically, once finalized, revised standards are litigated. More stringent NAAQS could cause certain areas in Georgia to be reclassified as "nonattainment," which may require additional emissions reductions from certain power plants we own or co-own to bring those areas into "attainment." Although our coal-fired plants already have control systems for these pollutants installed or being installed, the implementation of new or revised NAAQS could lead to additional compliance requirements. The costs of any additional pollution control equipment that could be required 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 the CAIR, the CSAPR imposed cap and trade programs for sulfur dioxide and nitrogen oxides emissions on fossil fuel-fired electric generating units located in covered states, including Georgia. Subsequently, the U.S. Court of Appeals for the D.C. Circuit vacated the CSAPR, remanding it back to EPA for further consideration, leaving the CAIR in place

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pending further action by EPA. However, that decision was appealed and heard by the U.S. Supreme Court in December 2013, and a decision from that Court is expected later in 2014. While the outcome of the CSAPR proceedings may affect future operations of our co-owned units at Plants Scherer and Wansley, we do not anticipate the need to purchase allowances, given 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. Affected generating units will have until April 16, 2015 to comply; however, extensions for one or two years are possible under limited circumstances. The U.S. Court of Appeals for the District of Columbia Circuit heard the challenges to the MATS in December 2013, and a decision on the validity of the rule is expected in 2014.

    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 are being made. At Plant Scherer, the "multi-pollutant rule" requires operation of existing controls, which included activated carbon injection equipment, baghouses, SCRs and scrubbers. 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. If finalized as proposed, this new requirement could result in significant additional compliance and operational costs.

    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  – Executive Branch Action ."

    Air Quality Summary.     We believe that the controls already installed or being installed at Plants Scherer and Wansley will meet the requirements of the rules described above. However, depending on the final 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, we may have to incur significant capital expenditures and increased operating expenses at certain of our generating facilities, particularly Plants Scherer and Wansley.

    Compliance with the requirements of the Clean Air Act may also require increased capital or operating expenses on the part of Georgia Power. Any increases in Georgia Power's capital or operating expenses may cause an increase in the cost of power purchased from Georgia Power. See " OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES  – Member Power Supply Resources – Georgia Power Block Purchase. "

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Carbon Dioxide Emissions and Climate Change

    Efforts to limit emissions of carbon dioxide from power plants continue. Such limitations on emissions could originate in the Congress, the executive branch or the courts.

    Emissions of carbon dioxide from our plants totaled approximately 9.8 million short tons in 2013. In 2013, 29% 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 any greenhouse gas-related legislation or regulation, while another 24% came from our gas-fired facilities which would also be somewhat impacted but not to the same extent as the coal-fired plants. The remaining generation (47%) came from our interests in the nuclear Plants Vogtle and Hatch, which would likely not be impacted by any climate change legislation or regulation aimed at reducing greenhouse gas emissions.

    Pending Legislation.     At this time, we do not anticipate that the second session of the 113 ^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.

    Executive Branch Action.     President Obama has highlighted reducing greenhouse gas emissions as one of the priorities for his second term 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 issued a series of rules that apply the Clean Air Act PSD and Title V programs to stationary source emissions of greenhouse gases. These rules are now on appeal to the U.S. Supreme Court, and a decision on their validity and application to stationary sources like our power plants may be issued later in 2014.

    In 2013, President Obama announced his Climate Action Plan, ostensibly to implement a pledge to reduce domestic emissions of greenhouse gases by 17% below 2005 levels. Underpinning the plan is a focus on carbon emissions from power plants. A Presidential Memorandum, issued on June 25, 2013, directed EPA to perform two tasks: (1) to propose by September 20, 2013 New Source Performance Standards (NSPS) for greenhouse gas emissions from new power plants, and finalizing the September proposal in a timely fashion; and (2) to propose NSPS standards or guidelines (as appropriate) for modified, reconstructed and existing power plants by June 1, 2014, finalizing those NSPS standards and guidelines by June 1, 2015 and requiring states to submit plans for implementing the finalized guidelines for existing power plants by June 30, 2016. EPA's NSPS guidelines for existing sources presumably would apply to existing coal-fired electric generating facilities, including Plants Scherer and Wansley and may apply to our gas-fired facilities as well.

    Litigation.     While litigation related to carbon dioxide emissions continues on numerous fronts, we cannot predict the outcome of such litigation, or the effect it could have on any of the power plants that we own.

    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 substantial capital expenditures and/or increased operating costs at our fossil-fuel fired power plants, especially Plants Scherer and Wansley.

Coal Combustion Residuals

    In May 2010, EPA proposed two alternative approaches for regulating coal combustion residuals from electric utilities: regulation as listed "special wastes" under hazardous wastes rules or as solid waste. Although EPA proposes to exempt the beneficial use of coal combustion residuals, a designation as hazardous waste may limit or eliminate beneficial reuse options. Adoption of either approach may require closure of or significant changes to existing storage units, extended plant outages, construction of lined landfills and groundwater monitoring facilities, and additional material management and financial assurance requirements. A variation of the second approach might not require early closure of existing wet storage facilities. EPA has indicated that it will take further action on this rule in late 2014. Depending upon which method of regulation EPA selects, if any, preliminary estimates by many utilities and industry groups suggest

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that compliance costs are greater than originally anticipated by EPA and could be significant; however, any compliance costs will depend on the final form of the rules adopted. Based on the assumption that coal combustion residues will continue to be regulated as non-hazardous solid waste, preliminary estimates suggest that our compliance costs could be approximately $250 million or potentially more and occur in the 2017 to 2021 period. Estimated costs are based on pre-screening figures that should be distinguished from the more formalized cost estimates provided for projects that are more definite as to scope and timing and the ultimate impacts associated with either proposal 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. On June 7, 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 is under a 2012 court-approved settlement to finalize the guidelines by May 2014, although EPA has recently indicated that it would seek further extension of this deadline. The impacts of these guidelines cannot be determined at this time and will depend on the final regulations and any ensuing litigation.

    In February 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 November 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 a key use of water in Georgia, 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 impact. In April 2011, EPA proposed new national requirements under section 316(b) to reduce the impact on fish and other aquatic life caused by cooling water intake structures at existing power plants and manufacturing facilities. Applying to existing power generating facilities withdrawing more than two million gallons per day from waters of the United States and using at least 25% of the water exclusively for cooling, the proposal primarily requires utilities to add cooling towers on power plants that currently utilize "once through" cooling systems. The proposed regulations would apply to Plants Hatch, Vogtle, Scherer and Wansley; however, each of these plants already has operational cooling towers and any effects of the rule are not expected to be significant. Although EPA was under court order to issue a final rule by January 2014, it missed that deadline and negotiated an extension to April 17, 2014. Any effect on our plants will depend on the content of the final rule and the results of any ensuing legal challenges.

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

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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 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. Preliminary 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. These contracts require each such owner to pay a fee, which is currently just under one dollar per megawatt-hour for the net electricity generated and sold by each of its reactors.

    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. Based on our ownership interest, we received $16.2 million in 2012 as a result of the settlement of the first lawsuit seeking damages for

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certain spent nuclear fuel costs incurred from 1998 through 2004, See Note 1 of Notes to Consolidated Financial Statements for information regarding the status of this litigation.

    In subsequent claims filed against the Department of Energy by Georgia Power as agent for the co-owners, damages for spent nuclear fuel storage costs at Hatch and Vogtle Units No. 1 and No. 2 are being sought for the period of January 2005 through December 2013. The final outcome of these matters cannot be determined at this time.

    In November 2013, the U.S. Court of Appeals for the District of Columbia Circuit 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. In accordance with the court's order, the Department of Energy has submitted a proposal to the Congress to change the fee to zero. That proposal is pending before the Congress and will become effective after 90 days of legislative session from the time of the submittal unless the Congress enacts legislation that impacts the proposed fee change. We are continuing to pay the fee of approximately $9.2 million annually based on our ownership interests. The ultimate outcome of this matter cannot be determined at this time.

    An on-site dry storage facility at Vogtle Units No. 1 and No. 2 began operation in October 2013. At Hatch, an on-site dry spent fuel storage facility is also operational. Facilities at both plants 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 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

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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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