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

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FORM 10-K

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

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

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

       Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No o

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

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

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

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

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

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

       Documents Incorporated by Reference: None

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OGLETHORPE POWER CORPORATION

2010 FORM 10-K ANNUAL REPORT

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PART I

ITEM 1.  BUSINESS

OGLETHORPE POWER CORPORATION

General

    We are a Georgia electric membership corporation (an EMC) incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 39 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 the largest electric cooperative in the United States in terms of 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 209 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 credit.

    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 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, with a small amount supplied to seven of our members through a power sale agreement we acquired in conjunction with the acquisition of the Hawk Road Energy Facility in 2009. 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.")

    We have interests in 29 operating generating units, fueled by nuclear, coal, gas, oil and water. (See "OUR POWER SUPPLY RESOURCES" and "PROPERTIES – Generating Facilities.")

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    In 2010, three of our members, Cobb EMC, Jackson EMC and Sawnee EMC, accounted for 14.5%, 11.6% and 10.6% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2010.

Wholesale Power Contracts

    The wholesale power contracts we have with each member are substantially similar and extend through December 31, 2050. 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 any approved future resources, whether or not that member has elected to participate in the future resource. 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.

    To acquire future resources, we are required to obtain the approval of 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. We can make certain resource modifications if approved by more than 50% of the members of our board of directors and 50% of our members.

    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 2010, we supplied energy that accounted for approximately 56% 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 our rates as necessary so that the revenues derived from

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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.

    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. 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. Margins for interest ratio is the ratio of margins for interest to total interest charges for a given period. Margins for interest is the sum of:

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our net margins (which includes our revenues subject to refund at a later date but excludes provisions for (i) non-recurring charges to income, including the non-recoverability of assets or expenses, except to the extent we determine to recover these charges in rates, and (ii) refunds of revenues we collected or accrued subject to refund), plus

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interest charges, whether capitalized or expensed, on all indebtedness secured under the first mortgage indenture or by a lien equal or prior to the lien of the first mortgage indenture, including amortization of debt discount or premium on issuance, but excluding interest charges on indebtedness assumed by Georgia Transmission Corporation (which, as described below, was formed in 1997 to operate the transmission business we previously owned), plus

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any amount included in net margins for accruals for federal or state income taxes imposed on income after deduction of interest expense.

    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.

    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 – Rates and Regulation.")

    The rate schedule formula also includes a prior period adjustment mechanism designed to ensure that we achieve the minimum 1.10 margins for interest ratio. Amounts, if any, by which we fall short of the minimum 1.10 margins for interest ratio are accrued as of December 31 of the applicable year and collected from our members during the period April through December of the following year. The rate schedule formula 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.

    To enhance margin coverage during the period of generation facility construction and acquisition, our board of directors approved budgets for 2010 and 2011 to achieve a 1.14 margins for interest ratio, above the minimum 1.10 ratio required by the first mortgage indenture. As our construction and acquisition program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below 1.10.

    Under the first mortgage indenture and related loan contract with the Rural Utilities Service, adjustments to our rates to reflect changes in our budgets are generally not subject to Rural Utilities Service approval. Changes to the rate schedule under the wholesale power contracts are generally subject to Rural Utilities Service approval. Our rates are not subject to the approval of

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any other federal or state agency or authority, including the Georgia Public Service Commission.

Relationship with Smarr EMC

    Smarr EMC is a Georgia electric membership corporation owned by 36 of our 39 members. Smarr EMC owns two combustion turbine facilities with aggregate capacity of 709 megawatts. We provide operations, financial and management services for Smarr EMC. (See "OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.")

Relationship with Georgia Transmission Corporation

    We and our 39 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.

    In 1997, Georgia Transmission assumed certain indebtedness associated with pollution control bonds originally issued on our behalf. If Georgia Transmission fails to satisfy its obligations under this debt, we remain liable for any unsatisfied amounts. Georgia Transmission plans to refund all of this existing assumed indebtedness by April 2012. (See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Off-Balance Sheet Arrangements.")

    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 38 of our 39 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, human resources, facility management, telecommunications and information technology at cost.

    As of December 31, 2010, we had approximately $6.4 million of loans outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $6.0 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 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-guaranteed loan

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funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, Rural Utilities Service-guaranteed loan funds are subject to increased uncertainty because of budgetary and political pressures faced by Congress. The President's budget for fiscal year 2011, which has not been adopted, proposed to reduce funding by almost 40% from the 2010 levels of $6.5 billion and, in support of the President's commitment to reduce inefficient fossil-fuel subsidies, would prohibit loans for new or existing fossil-fueled generation. The proposal would limit the use of electric loan funds to renewable energy, transmission, distribution and carbon-capture projects on generation facilities. The President's budget proposal for fiscal year 2012 provides for $6 billion in guaranteed loans – a reduction of less than 10% from 2010 levels. The same restrictions as proposed for 2011 would apply, except that up to $2 billion would be 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-guaranteed loans that may be available to us in the future.

    We have a loan contract with the Rural Utilities Service in connection with the first mortgage indenture. 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 rate schedule contained in the wholesale power contracts,

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changes to plant ownership and operating agreements,

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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, and

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in limited circumstances, issuance of additional secured and unsecured debt.

    The extent of the Rural Utilities Service's approval rights under the loan contract with us is substantially less than the supervision and control the Rural Utilities Service has traditionally exercised over borrowers under its standard loan and security documentation. In addition, the first mortgage indenture improves our ability to borrow funds in the capital markets relative to the Rural Utilities Service's standard mortgage. The first mortgage indenture constitutes a lien on substantially all of the tangible and certain intangible property we own.

Relationship with Georgia Power Company

    Our relationship with Georgia Power is a significant factor in several aspects of our business. Georgia Power is responsible for the construction and operation of all of our co-owned generating facilities, except the Rocky Mountain Pumped Storage Hydroelectric Facility, on behalf of itself as a co-owner and as agent for the other co-owners. 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."

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

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only limited competition in Georgia, this competition has given our members the opportunity to develop resources and strategies to prepare for 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, and no bill is currently pending in the Georgia legislature which would amend the Georgia Territorial Act or otherwise affect the exclusive right of our members to supply power to their current 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 at this time the results of these matters 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 (including financing and plant co-ownership arrangements) 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 (see "ENVIRONMENTAL AND OTHER REGULATIONS – Carbon Dioxide Emission and Climate Change – Pending Legislation" and "RISK FACTORS"). 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 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 their 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.

    Many members are also providing or considering proposals to provide non-traditional products and services such as telecommunications and other services. In 2002, the Georgia legislature enacted legislation empowering the Georgia Public Service Commission to authorize member affiliates to market natural gas. The Georgia Public Service Commission is required to

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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. 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 climate, whether as a result of greenhouse gas emissions or otherwise. Energy revenues track 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 generating assets and power purchased from other suppliers. In 2010, we supplied approximately 56% of the retail energy requirements of our members.

Generating Plants

    We have interests in 29 operating generating units. The Municipal Electric Authority of Georgia, the City of Dalton and Georgia Power also have interests in eight of these units - at Plants Hatch, Vogtle, Wansley and Scherer. Georgia Power serves as operating agent for these units. Georgia Power also has an interest in Rocky Mountain, which we operate.

    See "PROPERTIES" for a description of our generating facilities, fuel supply and the co-ownership arrangements and Note 4 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."

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 2010, 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

    In conjunction with our acquisition of Hawk Road in 2009, we accepted assignment of a power purchase and sale agreement pursuant to which we sell 500 megawatts of capacity and associated energy to seven of our members, with a term through December 31, 2015.

Other Power System Arrangements

    We have interchange, transmission and/or short-term capacity and energy purchase or sale agreements with approximately 50 utilities, 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. We are currently using only about one-third of these agreements, primarily to facilitate the short-term management of our resource portfolio.

Future Power Resources

Plant Vogtle Units No. 3 and No. 4

    We are participating in 30% of the costs of the construction of two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4, scheduled for commercial operation in 2016 and 2017, respectively.

    In April 2008, Georgia Power, for itself and as agent for us, The Municipal Electric Authority of Georgia and the City of Dalton (the Owners), signed an Engineering, Procurement and Construction Contract with Westinghouse Electric Company, LLC and Stone & Webster, Inc. (the Consortium). Pursuant to the contract, the Consortium 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 Owners will pay a purchase price that is subject to certain price escalation and adjustments, including index-based adjustments, as well as adjustments for change orders and performance bonuses. This agreement was amended in February 2010 to replace certain of the index-based adjustments with fixed escalation amounts.

    Each Owner is severally, not jointly, liable to the Consortium based on its ownership share. The contract includes certain liquidated damages upon the Consortium's failure to comply with schedule and performance guarantees, as well as certain bonuses payable to the Consortium for early completion and unit performance. The Consortium'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., respectively. In the event of certain credit rating

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downgrades of any Owner, that Owner would be required to provide a letter of credit or other credit enhancement to the Consortium. In addition, the Owners may terminate the contract at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the contract under certain circumstances, including delays in receipt of the combined construction permits and operating licenses, certain Owner suspension or delays of work, action by a governmental authority to stop work permanently, certain breaches of the contract by the Owners, Owner insolvency and certain other events.

    The Owners and the Consortium have established both informal and formal dispute resolution procedures in order to resolve issues that commonly arise during the course of constructing a project of this magnitude. Southern Nuclear Operating Company, on behalf of the Owners, has initiated both formal and informal claims through these procedures, including ongoing formal and informal claims, and anticipates that further issues are likely to arise in the future. To date, the Owners have successfully used both the informal and formal procedures to resolve disputes and expect to resolve any existing and future disputes through these procedures as well.

    Our rights and obligations with respect to these additional units are contained in an Ownership Participation Agreement, the Plant Vogtle Operating Agreement (amended to include Units No. 3 and No. 4), and the Nuclear Managing Board Agreement (amended to include Units No. 3 and No. 4). The Ownership Participation Agreement is similar to the agreement that covers Units No. 1 and No. 2.

    In August 2009, the Nuclear Regulatory Commission issued an early site permit and a limited work authorization, allowing subsurface foundation work to proceed in advance of a combined construction permit and operating license.

    In March 2008, Southern Nuclear Operating Company, on behalf of the Owners, filed an application for combined construction permits and operating licenses for two 1,100 megawatt units, using the Westinghouse AP1000 technology. An Atomic Safety and Licensing Board panel was appointed to preside over hearings in the combined construction permit and operating license proceeding.

    In December 2010, Westinghouse submitted an AP 1000 Design Certification Amendment to the Nuclear Regulatory Commission. In February 2011, the Nuclear Regulatory Commission announced that it was seeking public comment on a proposed rule to approve the Design Certification Amendment and amend the certified AP 1000 reactor design for use in the United States. The Advisory Committee on Reactor Safeguards also issued a letter in January 2011 endorsing the issuance of the license for Units No. 3 and No. 4. The Nuclear Regulatory Commission schedule for this proceeding contemplates a decision in late 2011.

    Our estimated total costs for the new units, including allowance for funds used during construction, are approximately $4.2 billion. As of December 31, 2010, construction work in progress for this project was $867 million.We submitted a loan application to the Department of Energy seeking partial funding for these proposed nuclear units and have been offered a conditional term sheet for 70% of the eligible project costs. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures" and " – Financing Activities."

    On March 11, 2011, a major earthquake and tsunami struck Japan and caused substantial damage to the nuclear generating units at the Fukushima Daiichi generating plant. According to published reports, the owner of these units is working to stabilize these units following a loss of operation of the cooling systems for the units which has led to the release of radiation. Both Georgia Power, on behalf of the Owners, and we continue to monitor this developing situation. To date, Georgia Power has not identified any immediate impacts to the licensing and construction of Vogtle Units No. 3 and No. 4 or the operation of our existing nuclear units. 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.

Murray I and II Energy Facilities

    On January 31, 2011, we entered into a Purchase and Sale Agreement with KGen LLC and, for specified purposes, its parent company, KGen Power Corporation, to acquire KGen LLC's wholly owned subsidiary, KGen Murray I and II LLC, which owns the Murray I and

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Murray II combined cycle electric generation facilities located near Dalton, Georgia. These facilities consist of two natural gas-fired combined cycle units that have an aggregate summer planning reserve generation capacity of approximately 1,220 megawatts. The purchase price, exclusive of working capital and other closing adjustments, is approximately $531 million.

    Our board of directors and members and KGen Power's board of directors and shareholders have approved this transaction; however, this acquisition remains subject to receipt of applicable regulatory approvals and other customary closing conditions and, as a result, may not result in a completed transaction. If we complete this acquisition, we anticipate that it will close in April 2011. The acquisition would include an existing power purchase and sale agreement with Georgia Power for the entire output of Murray I through May 31, 2012. Initially, both units are planned to be operated independently of the other generating facilities we own and operate, but will be integrated into our system as needed.

    Our members have also subscribed for a two on one, 605 megawatt, combined cycle plant with anticipated commercial operation in 2015. The estimated cost for this facility is approximately $750 million, including allowance for funds used during construction. However, upon acquisition of the Murray facilities, we would cancel the development of this combined cycle plant.

    We have submitted a loan application to the Rural Utilities Service for long-term financing of this acquisition. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures" and " – Financing Activities."

Biomass Plant

    Our members had subscribed for a 100 megawatt biomass-fueled generating plant. We acquired a site in Warren County, Georgia, conducted preliminary engineering work and environmental analyses, and requested proposals for major equipment and for an engineering, procurement and construction contract. This plant was originally planned for commercial operation in 2014. However, due primarily to regulatory and legislative uncertainty, we have deferred completion of this plant. We continue to monitor regulatory and legislative developments related to biomass electricity generation.

    Our estimated cost to construct this facility was $477 million, including allowance for funds during construction and we submitted a loan application to the Rural Utilities Service for financing of this project in the event development is resumed. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures" and " – Financing Activities."

    We acquired a site for a second biomass plant, which had been considered for commercial operation in 2015, but which has been delayed for an indefinite period of time.

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"). In addition to Vogtle Units No. 3 and No. 4 and the Murray facilities, we have identified for our members other generation resource development possibilities to help meet their power supply needs over the next ten years. Our members have given general approval for the future development of certain quantities of gas-fired combustion turbine plants and combined cycle plants that may be planned for commercial operation prior to December 31, 2016, subject to future member subscription for specific projects. We are continuing development activities to be prepared for construction as needed.

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OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES

Member Demand and Energy Requirements

    Our members are listed below and include 39 of the 42 electric distribution cooperatives in the State of Georgia.

Altamaha EMC
Amicalola EMC
Canoochee EMC
Carroll EMC
Central Georgia EMC
Coastal EMC (d/b/a Coastal Electric Cooperative)
Cobb EMC
Colquitt EMC
Coweta-Fayette EMC
Diverse Power Incorporated, an EMC
Excelsior EMC
Flint EMC (d/b/a Flint Energies)
Grady EMC
GreyStone Power Corporation, an EMC
Habersham EMC
Hart EMC
Irwin EMC
Jackson EMC
Jefferson Energy Cooperative, an EMC
Little Ocmulgee EMC
Middle Georgia EMC
Mitchell EMC
Ocmulgee EMC
Oconee EMC
Okefenoke Rural EMC
Pataula EMC
Planters EMC
Rayle EMC
Satilla Rural EMC
Sawnee EMC
Slash Pine EMC
Snapping Shoals EMC
Southern Rivers Energy, Inc., an EMC
Sumter EMC
Three Notch EMC
Tri-County EMC
Upson EMC
Walton EMC
Washington EMC

    In December 2009, Flint EMC became our 39^th member. Currently, Flint does not have a percentage capacity responsibility in any of our operating generation resources; however, it is participating in generation resources under construction and has the right to participate in any future generation resources we may acquire or construct. Since Flint is not a participant in our operating generation resources, we do not supply any of its capacity or energy requirements. However, all the historical member statistics in this report include Flint.

    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 39 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 2008 through 2010, and also shows the amount of their energy requirements that we supplied. From 2008 through 2010, demand and energy requirements of the members increased at an average annual compound rate of 0.2% and 3.5%, respectively.

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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. 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 a premise 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 member 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% (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 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

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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 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 2012 proposes to reduce funding by less than 10% from 2010 levels for the Rural Utilities Service electric program. The proposed funding would be available only for transmission, distribution, renewable energy and carbon capture projects for generation 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 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.

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    For information about our relationship with Georgia System Operations, see "OGLETHORPE POWER CORPORATION – Relationship with Georgia System Operations."

Member Power Supply Resources

Oglethorpe Power Corporation

    In 2010, we supplied approximately 56% 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.") Additionally, effective May 2009, we assumed a power purchase and sale agreement with seven of our members in connection with our acquisition of Hawk Road. (See "OUR POWER SUPPLY RESOURCES – Power Purchase and Sale Agreements – 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. In 2010, 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 36 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, 217 megawatt gas-fired combustion turbine facility, and Sewell Creek Energy Facility, a four-unit, 492 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. See "OGLETHORPE POWER CORPORATION – Relationship with Smarr EMC."

Green Power EMC

    Our members are also members 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.

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, in addition to providing other services to its members.

Georgia Power Block Purchase

    Thirty members have entered into 10-year power supply contracts with Georgia Power under which they purchase an aggregate of 750 megawatts of capacity and associated energy. Delivery under the agreements began January 1, 2005.

Other Member Resources

    Our members are obtaining their remaining power supply requirements from various sources. Thirty-two members have entered into contracts with third parties for all of their incremental power requirements, with remaining terms ranging from 4 to 20 years. Some contracts, for fixed quantities, extend more than 17 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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ENVIRONMENTAL AND OTHER REGULATION

General

    As is typical for electric utilities, we are subject to various federal, state and local air and water quality requirements which, among other things, regulate emissions of pollutants into the air and discharges of other pollutants, including heat, into waters of the United States. We are also subject to federal, state and local waste disposal requirements that regulate the manner of transportation, storage and disposal of various types of waste.

    In general, environmental requirements are becoming increasingly stringent. Although we have installed or are in the process of installing environmental control systems at our plants (including systems to reduce emissions of sulfur dioxide, oxides of nitrogen and mercury at Plants Scherer and Wansley) to ensure continued compliance with existing requirements, new requirements could be imposed in the future. New requirements may substantially increase the cost of electric service, by requiring changes in the design or operation of existing facilities or changes or delays in the location, design, construction or operation of new facilities. Failure to comply with these requirements could result in the imposition of civil and criminal penalties as well as 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 or 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 with applicable current and future regulations.

    Our capital expenditures and operating costs will continue to reflect compliance 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 and other pollutants from affected electric utility units, including the coal-fired units at Plants Wansley and Scherer. The Clean Air Act related actions that appear to be the most significant follow.

    Changes in the National Ambient Air Quality Standards (NAAQS).    Many of the NAAQS have recently been revised or are in the process of revision to make them more stringent. Revisions made final are being litigated. More stringent NAAQS could cause certain areas in Georgia to be reclassified as "nonattainment," which may require further emissions reductions from power plants we own or co-own there and in surrounding areas, to bring those areas into "attainment." Although the co-owned coal-fired plants already have control systems installed or being installed for these pollutants, the costs of any additional pollution control equipment that could be required because of these NAAQS cannot be determined at this time.

    Clean Air Interstate Rule and the Clear Air Transport 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 2010, EPA proposed the Clean Air Transport Rule (CATR) to replace the CAIR. Similar to CAIR, EPA's preferred approach in the CATR would impose cap and trade programs for sulfur dioxide and nitrogen oxides emissions. In Georgia, a sulfur dioxide emissions cap would be imposed in two phases, with the first phase beginning in 2012 and the second, more stringent phase in 2014. Reductions of nitrogen oxides emissions would be implemented using two caps, for annual and ozone season emissions, both of which would begin in Georgia in 2012. Subsequent notices of data availability have proposed alternative EPA methods for allocating CATR sulfur dioxide and nitrogen oxides emissions allowances, possibly affecting compliance plans for our owned and co-owned units. Georgia may determine

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CATR allowance allocations in the future. EPA plans to finalize the CATR to replace the CAIR later in 2011.

    Electric Generating Unit Maximum Achievable Control Technology Rules and State Mercury Rules.    After D.C. Circuit vacatur and remand of a mercury control regulation and a companion regulation delisting electric generating units from the hazardous air pollutant source list in Section 112 of the Clean Air Act, the Supreme Court dismissed a subsequent appeal of the decision. In response to that litigation and a separate suit seeking further regulation, EPA proposed a rule in March of 2011 establishing maximum achievable control technology (MACT) limits for certain hazardous air pollutants (including mercury) for coal and oil-fired electric generating units. EPA intends to finalize the rule by November 2011. Georgia's current mercury rules include a "multi-pollutant rule" that requires operation of the existing controls (for Plant Wansley) and existing and planned controls (for Plant Scherer) as follows – selective catalytic reduction systems (reducing nitrogen oxides) and scrubbers (reducing sulfur dioxide and mercury) at Plant Wansley; and activated carbon injection and baghouses (reducing mercury), scrubbers (reducing sulfur dioxide) and selective catalytic reduction (reducing nitrogen oxides) at Plant Scherer. EPA's MACT proposed rule could affect Georgia's mercury rule (or other current state rules).

    New Source Review.    In November 1999, the United States Justice Department, 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, among other facilities, Scherer Unit Nos. 3 and 4. We are not currently named in the lawsuits and we do not have an ownership interest in the named units of Plant Scherer. However, we can give no assurance that units in which we have an ownership 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 required to remedy our violations at co-owned facilities.

    Rulemakings that began in 2009 now impose new source review requirements on greenhouse gases (including carbon dioxide) under the Prevention of Significant Deterioration (PSD) preconstruction permitting program. (See "Carbon Dioxide Emissions and Climate Change – Executive Branch Action.") As a result, PSD review for major stationary sources of greenhouse gases was, according to EPA, triggered on January 2, 2011.

    Air Quality Summary.    We believe that the controls being designed and/or installed at Plants Wansley and Scherer will meet the requirements of the rules described above. However, because (1) several of these proposed or final Clean Air Act regulations could require control of the same emissions, (2) the compliance requirements remain uncertain, (3) litigation challenging some or all of these rules is likely, and (4) specific control technologies affect multiple emissions, we cannot determine the aggregate effect of these or future regulations.

    Depending on the final outcome of these developments, and the implementation approach selected by EPA and the State of Georgia with respect to environmental regulations, we may have to incur significant capital expenditures and increased operation expenses for the continued operation of Plants Wansley and/or Scherer.

    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.")

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.

    Pending Legislation.    Unlike last year, when legislation under consideration would have imposed new regulation or more stringent emissions limitations for greenhouse gases, including carbon dioxide, on power plants, several proposals in the 112^th Congress would ostensibly limit the authority of EPA to continue regulation of greenhouse gases. However, even if such legislation were passed, it remains possible that Congressional action may regulate emissions of greenhouse gases, either directly or through some type of energy

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legislation that could include a national renewable electricity standard. We cannot predict at this time whether any legislation will be passed that would regulate greenhouse gas emissions from our power plants, directly or indirectly, nor can we predict the impacts from any relevant federal legislation. Emissions of carbon dioxide from our plants totaled approximately 12.8 million short tons in 2010.

    Executive Branch Action.    In 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA 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. The Court directed EPA to decide whether such regulation is needed. In response, EPA issued a final rule in December 2009 determining that certain greenhouse gas emissions (including carbon dioxide) from new motor vehicles endanger public health or welfare, following a September 2009 rule requiring the annual reporting (beginning in 2011 for 2010 emissions) of greenhouse gas emissions by many industries, including the electric utility industry, and by fossil fuel suppliers. In April 2010, EPA issued a rule that establishes when a pollutant (like carbon dioxide) becomes "subject to regulation" under the Clean Air Act for purposes of PSD and Title V. In another rule, issued in May 2010, EPA established emission standards for certain greenhouse gases (again including carbon dioxide) for new light-duty vehicles, determining that such standards will take effect on January 2, 2011. Further, in another rule, promulgated in June 2010, EPA established significance thresholds for greenhouse gas emissions (including carbon dioxide) and a schedule whereby new or modified stationary sources exceeding such thresholds will become regulated under the PSD and Title V programs. Together, these rules establish a three-step schedule for application of PSD and Title V to stationary sources. The first two steps of regulation began January 2, 2011 and will begin July 1, 2011 for larger sources of greenhouse gases, while a possible third step for smaller greenhouse gas sources may begin April 30, 2016. Finally, EPA has stated its intention to issue a revised New Source Performance Standard (NSPS) for steam generating units operated by electric utilities (and other industrial and commercial facilities) in 2011. The final rules discussed above are subject to numerous petitions for review, and challenges to future rules may be brought if and when such rules are finalized. We cannot predict at this time how further developments may affect the regulation of greenhouse gas emissions from our power plants, including capital requirements.

    Litigation.    Litigation related to carbon dioxide emissions continues on numerous fronts, and the outcome of such litigation could affect the power plants we own. For example, in 2004, Attorneys General from eight states and the Corporation Counsel of New York filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaint alleges that the companies' emissions of carbon dioxide contribute to global warming, which the plaintiffs claim is a public nuisance. Plaintiffs seek injunctive relief only to abate the alleged nuisance. In September 2009, the U.S. Court of Appeals for the Second Circuit vacated an earlier dismissal of the plaintiffs' claims, remanding the case back to the Southern District. In December 2010, the Supreme Court agreed to hear an appeal of the case, and such appeal remains pending.

    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 Wansley and Scherer) and potentially impact the ability to permit new sources.

Other Environmental Regulation

    In May 2010, EPA proposed two alternative approaches for regulating coal combustion byproducts from electric utilities: regulation as listed "special wastes" under hazardous wastes rules or as solid wastes (a variation of this second approach might not require early closure of existing wet storage facilities). Although EPA proposes to exempt the beneficial use of coal combustion byproducts, a designation as hazardous waste may limit or eliminate beneficial reuse options. Further, 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. Depending upon which method of regulation EPA selects, if any, preliminary estimates by many utilities and industry groups suggest that compliance costs are greater than originally anticipated

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by EPA and could be significant; however, any compliance costs will depend on the final form of the rules adopted, if any, and are indeterminate at this time.

    Since 2005, EPA has been carrying out a review of wastewater discharges from coal-fired power plants to determine whether new Steam Electric Power Generating effluent guidelines that cover wastewater discharge standards under the Clean Water Act are needed. In August 2008, EPA published an interim report on the status of the studies undertaken and the findings to date. Upon completion of the study, EPA announced in late 2009 its intention to revise these guidelines, proposing to adopt such revisions by 2013. We cannot predict at this time whether any such regulations by EPA, or any action by the State of Georgia, will impact the current methods of wastewater or ash disposal utilized at our plants.

    In February 2008, the Georgia legislature adopted a comprehensive state water plan for Georgia. The stated purpose of this plan is to guide Georgia in managing water resources in a sustainable manner to support the state's economy, to protect public health and natural systems, and to enhance the quality of life for all citizens. The plan lays out statewide policies, management practices, and guidance for regional planning. The provisions of this plan are intended to guide river basin and aquifer management plans and regional water planning efforts statewide in a manner consistent with existing state law. Power generation is a key use of water in the state, and any regulations or other enforceable requirements developed in response to this plan or subsequent regional plans may have substantial effects on the operations of our facilities or future facilities we construct or acquire. The impacts of this water plan cannot be determined at this time and will depend on the development of future implementing regulations.

    We are subject to other environmental statutes including, but not limited to, the Georgia Water Quality Control Act, the Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act, and to the regulations implementing these statutes. We do not believe that compliance with these statutes and regulations will have a material impact on our financial condition or results of operations. Changes to any of these laws, some of which are being reviewed by Congress, could affect many areas of our operations. Although compliance with new environmental legislation could have a significant impact on us, those 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, however, do not believe that the current actions will have a material adverse effect on our financial position or results of operations.

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 has issued an early site permit and a limited work authorization for two additional units at Plant Vogtle. An application has been filed with the Nuclear Regulatory Commission for combined construction permits and operating licenses that would allow the construction and operation of two

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additional units at Plant Vogtle. See "OUR POWER SUPPLY RESOURCES – Future Power Resources."

    For a discussion regarding the events at the Fukushima nuclear plant in Japan and the potential effects on our existing nuclear plants and the development and construction of Plant Vogtle Units No. 3 and No. 4, see "Future Power Resources – Plant Vogtle Units No. 3 and No. 4" and "RISK FACTORS."

    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, is pursuing legal remedies against the Department of Energy for breach of contract. See Note 1 of Notes to Consolidated Financial Statements for information regarding the status of this litigation.

    Plants Hatch and Vogtle currently have on-site spent-fuel wet storage capacity and Plant Hatch has an on-site dry storage facility. The on-site dry storage facility for Plant Hatch became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant. Plant Vogtle's spent fuel pool storage is expected to be sufficient until 2014. We expect that procurement of on-site dry storage capacity at Plant Vogtle will commence in sufficient time to maintain full-core discharge capability to the spent fuel pool. (See Note 1 of Notes to Consolidated Financial Statements.)

    For information concerning nuclear insurance, see Note 8 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

    We are subject to the provisions of the Federal Power Act applicable to licensees with respect to their hydroelectric developments. Rocky Mountain is a hydroelectric project subject to licensing by the Federal Energy Regulatory Commission.

    We have a license, expiring in 2027, for Rocky Mountain. 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.

    The Energy Policy Act of 2005 amended the Federal Power Act to authorize the Federal Energy Regulatory Commission to establish regional reliability organizations authorized to enforce reliability standards and to establish clear responsibility for the commission to prohibit manipulative energy trading practices. As a generation owner and participant in wholesale power transactions, we could be subject to penalties for violation of these standards and regulations.

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ITEM 1A.  RISK FACTORS

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

We are undertaking a large capital expansion program that will significantly increase our long-term debt.

    We are undertaking a large capital expansion program to meet the future energy needs of our members, and we will incur a significant amount of long-term debt in connection with this capital expansion program. As of December 31, 2010, we had approximately $4.8 billion of long-term debt outstanding. For 2011 through 2017, we project that we will invest approximately $4 billion to construct and acquire additional generation facilities and to upgrade our existing generation facilities. As a result, we project that we will have approximately $9 billion in long-term debt outstanding by the end of 2017. See "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures."

    This significant increase in long-term debt is expected to increase the cost of electric service we provide to our members. In addition, we will continue to be highly leveraged and certain of our financial metrics may weaken, which could impact our credit ratings. To address this situation, since 2009 our board of directors has approved budgets to achieve a greater margins for interest ratio than the minimum 1.10 margins for interest ratio required under the first mortgage indenture. For 2011, our board of directors approved a margins for interest ratio of 1.14. However, even with increased margins, due to the amount of incremental debt associated with new generation construction and acquisitions, our equity ratio will continue to decrease during the period of generation expansion. Any reduction in our credit ratings could increase our borrowing costs and decrease our access to the credit and capital markets.

We are exposed to cost uncertainty in connection with our construction projects at existing and new generating facilities.

    In connection with our construction projects related to new generating resources and upgrades to existing generating resources, we have committed to significant capital expenditures and investments. The completion of these construction projects without delays or cost overruns is subject to substantial risks, including:

•

permits, approvals and other regulatory matters;

•

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

•

continued public and policymaker support;

•

unforeseen engineering problems;

•

performance by engineering, construction or procurement contractors;

•

potential contract disputes;

•

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

•

work stoppages;

•

adverse weather conditions;

•

environmental and geological conditions;

•

unanticipated increases in the costs of materials and labor;

•

changes in project design or scope;

•

increases in our cost of debt financing; and

•

delays or increased costs to interconnect our facilities to transmission grids.

    In addition, the construction of large generating plants involves significant financial risk. Moreover, no nuclear plants have been constructed in the United States using advanced designs. Therefore, estimating the cost of construction of any new nuclear plant is inherently uncertain; however, our engineering, procurement and construction contract for the additional units at Plant Vogtle limits our exposure to increases in construction costs. Further, we rely on Georgia Power and Southern Nuclear to act as our agents for the development and construction of the additional units at Plant Vogtle and do not exercise direct control over the development and construction process.

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    All of these risks could have the effect of increasing the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.

Due in part to national initiatives or international negotiations, we may become subject to regulatory, legislative and/or judicial responses to climate change, compliance with which could be difficult and costly.

    Efforts to limit emissions of greenhouse gases, in particular, carbon dioxide, from power plants continue. Although climate change legislation has not been adopted at the federal level, EPA continues to move forward with the regulation of greenhouse gas emissions under the Clean Air Act. In 2009, EPA determined that certain greenhouse gas emissions, including carbon dioxide, from new motor vehicles endanger public health or welfare, and required the annual reporting of greenhouse gas emissions by many industries, including the electric utility industry. Effective January 2011, EPA has taken the position that carbon dioxide and other greenhouse gases are regulated pollutants under the Prevention of Significant Deterioration preconstruction permit program and the Title V operating permit program under the Clean Air Act, which apply to power plants and other commercial and industrial facilities. As a result, the construction of new facilities or major modifications to existing facilities could trigger the need for certain permits and the installation of the best available control technology for greenhouse gases. In addition, EPA plans to propose a revised New Source Performance Standard for steam generating units operated by electric utilities, and other industrial and commercial facilities in 2011 which will be finalized by mid-2012. Many of our electric generating facilities are potentially subject to these new or pending regulations.

    Unlike last year, when legislation was under consideration would have imposed new regulation or more stringent emissions limitations for greenhouse gases, including carbon dioxide, on power plants, several proposals in the 112^th Congress would ostensibly limit the authority of EPA to continue regulation of greenhouse gases. However, even if limiting legislation is passed, Congress may also decide to regulate emissions of greenhouse gases, either directly or through some type of energy legislation, that could include a renewable energy standard.

    Litigation over climate change issues, including greenhouse gas emissions has become more frequent in the United States. Such suits involve claims of various types, including property damage, personal injury, common law nuisance, including injunctive relief, challenges to issued permits and citizen enforcement of the Clean Air Act.

    International climate change negotiations under the United Nations Framework Convention on Climate Change continue, although outcomes that result in enforceable emissions limitations for our facilities do not appear likely in the coming year. International limits that secure United States approval appear dependant on limitations measures first being established by the United States.

    In 2010, our generation resources emitted approximately 12.8 million short tons of carbon dioxide. In 2010, 46% of our generation, excluding pumped storage, came from our interest in the coal-fired Plants Scherer and Wansley, which would be the most impacted by any greenhouse gas-related legislation or regulation, while another 10% came from our gas-fired facilities (which would also be somewhat impacted but not to the same extent as the coal-fired facilities). The remaining generation (44%) came from our interest in the nuclear Plants Vogtle and Hatch; these would not likely be impacted by any climate change regulation.

    The cost impact of legislation, regulation, new judicial interpretations of existing laws or regulations, or international obligations depends upon the specific requirements created and cannot be determined at this time. For example, the impact of currently proposed regulations relating to greenhouse gas emissions would depend on a variety of factors, including the specific greenhouse gas emission limits and the development of suitable technologies for reduction and/or sequestration of such emissions.

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

    We rely on access to external funding sources as a significant source of liquidity for capital expenditure requirements not satisfied by cash flow generated from operations. Unlike most investor-owned-utilities, electric

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cooperatives cannot issue equity securities and therefore rely almost entirely on debt financing. We and other electric generating cooperatives historically have relied on federal loan programs guaranteed by the Rural Utilities Service, a branch of the U.S. Department of Agriculture, in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of Rural Utilities Service funding levels are subject to the annual federal budget appropriations process, and therefore are subject to uncertainty because of periodic budgetary and political pressures faced by Congress. Although Congress has historically rejected proposals to curtail the Rural Utilities Service loan program, there can be no assurance that it will continue to do so. In addition, a new wave of generation construction nationwide among electric cooperatives is resulting in increased competition for available Rural Utilities Service funding. Because of these factors, we cannot predict the amount or cost of Rural Utilities Service-guaranteed loans that may be available to us in the future. See "BUSINESS – OUR POWER SUPPLY RESOURCES – Relationship with Rural Utilities Service" and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Liquidity and Sources of Capital – Sources of Capital."

    In connection with our share of the cost of constructing two additional nuclear units at Plant Vogtle, in May 2010 we signed a conditional term sheet that sets forth the general terms of a loan from the Federal Financing Bank and a related loan guarantee from the Department of Energy that would fund approximately 70% of eligible project costs, not to exceed $3.057 billion. We are now working with the Department of Energy to finalize the loan guarantee. However, final approval and issuance of a loan guarantee by the Department of Energy is subject to receipt of the combined construction permits and operating licenses for Vogtle Units No. 3 and No. 4 from the Nuclear Regulatory Commission (a decision is currently anticipated in the fourth quarter of 2011), negotiation of definitive agreements, completion of due diligence by the Department of Energy and satisfaction of other conditions. There can be no assurance that the Department of Energy will issue the loan guarantee to us.

    If the amount of Rural Utilities Service-guaranteed loan funds available to us in the future are further decreased or eliminated or we are unable to ultimately secure Department of Energy-guaranteed loan funds, we would have to seek alternative sources of debt financing, which will likely be at a higher cost.

    Therefore our reliance on access to both short-term and long-term capital market funding has become an increasingly important factor, particularly in light of the significant amount of generation expansion we have planned over the next seven years to meet the future energy needs of our members. Significant constraints on our access to, or increases in our cost of, capital may limit our ability to execute our business plan by impacting our ability to fund capital investments. We have successfully accessed the capital markets in the past, and believe that we will be able to maintain sufficient access to the capital markets based on our current credit ratings. However, our credit ratings reflect the views of the rating agencies, which could change at any point in the future. If one or more rating agencies downgrade us, our borrowing costs could increase and our potential pool of investors, funding sources and liquidity could decrease. In addition, if our credit ratings are lowered below investment grade, significant collateral calls may be triggered under certain agreements and contracts which would decrease our existing liquidity.

    The cost of our debt financing is affected by prevailing interest rate levels, and if these interest rate levels increase at the time we issue fixed rate debt or reset the interest rates on our variable rate debt, our interest costs will increase and our financial condition and future results of operations could be adversely affected.

    In addition, certain market disruptions could constrain, at least temporarily, our ability to maintain sufficient liquidity and to access capital on favorable terms or at all. These disruptions include:

•

market conditions generally, such as the recent uncertainty in the credit and capital markets;

•

economic downturns or recessions;

•

instability in the financial markets;

•

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

•

the overall health of the energy industry;

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•

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

•

lender concerns regarding potential cost overruns associated with nuclear construction;

•

war or threat of war; and

•

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

    If our ability to access capital becomes significantly constrained for any of the reasons stated above, or for any other reason, our ability to finance ongoing capital expenditures required to maintain existing generating facilities and to construct or acquire future power supply facilities could be limited, our interest costs could increase and our financial condition and future results of operations could be adversely affected.

Our costs of compliance with environmental laws and regulations are significant and have increased in recent years, and we may face increased costs related to environmental compliance, litigation or liabilities in the future.

    As with most electric utilities, we are subject to extensive federal, state and local laws and regulations regarding air and water quality which, among other things, regulate emissions of pollutants, such as particulate matter, sulfur dioxide, nitrogen oxides and mercury into the air and discharges of other pollutants, including heat, into waters. We are also subject to federal, state and local waste disposal requirements that regulate the manner of transportation, storage and disposal of various types of waste.

    Generally, these environmental regulations are becoming increasingly stringent and may require us to change the design or operation of existing facilities or change or delay the location, design, construction or operation of new facilities. These changes, in turn, may result in substantial increases in the cost of electric service.

    For example, in 2010, EPA proposed two alternative approaches for regulating coal combustion byproducts from electric utilities as either "special" wastes under hazardous waste rules or as solid wastes. Although EPA proposes to exempt the beneficial use of coal combustion byproducts, a designation as hazardous waste may limit or eliminate beneficial reuse options. Further, adoption of either approach may require closure of or significant changes to existing storage units, extended plant outages, construction of lined landfills, groundwater monitoring facilities and additional material management and financial assurance requirements. Depending upon which method of regulation EPA selects, if any, preliminary estimates by many utilities and industry groups suggest 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, if any, and are indeterminate at this time.

    To date, we have committed significant capital expenditures to achieve and maintain compliance with these regulatory requirements at our facilities, and we expect that we will make significant capital expenditures related to environmental compliance in the future.

    While we will continue to exercise our best efforts to comply with all applicable regulations, there can be no assurance that we will always be in compliance with all current and future environmental requirements. Failure to comply with these requirements, even if this failure is caused by factors beyond our control, could result in the imposition of civil and criminal penalties against us, as well as the complete shutdown of individual generating units not in compliance with these regulations.

    Additionally, litigation relating to environmental issues, including claims of property damage or personal injury caused by alleged exposure to hazardous materials, has increased in recent years. Likewise, actions by private citizen groups to enforce environmental laws and regulations are increasingly prevalent. While management does not currently anticipate that such litigation would have a material adverse effect on our financial condition, the ultimate outcome of any of these actions cannot be predicted.

    In addition, existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to our facilities. Revised or additional laws and regulations, and in particular climate change regulations, could result in significant additional expense and operating restrictions on our facilities or increased compliance costs which may result in significant increases in the cost of electric service. The financial impact of any laws would depend

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upon the specific requirements enacted and cannot be determined at this time.

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

    We own a 30% undivided interest in Plant Hatch and Plant Vogtle, each of which is a two-unit nuclear generating facility, and which collectively account for approximately 22% of our generating capacity. Our ownership interest in these facilities exposes us to various risks, including:

•

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

•

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

•

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

•

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

    Currently, there is no national repository for spent nuclear fuel, and progress towards such a repository has been disappointing. Spent nuclear fuel from Plants Hatch and Vogtle is currently stored in on-site storage facilities. We currently forecast that the on-site storage capabilities at Plants Hatch and Vogtle can be expanded to accommodate spent fuel through the life of the plants.

    We maintain an internal fund and an external trust fund for the estimated cost of decommissioning our nuclear facilities; however, it is possible that decommissioning costs and liabilities could exceed the amount of these funds.

    The Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of these facilities. If these facilities were found to be out of compliance with applicable requirements, the Nuclear Regulatory Commission may impose fines or shut down one or more units of these facilities until compliance is achieved. Revised safety requirements issued by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities. In addition, while we have no reason to anticipate a serious incident at either of these plants, if an incident did occur, it could result in substantial costs to us. A major incident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission to limit or prohibit the operation or licensing of any domestic nuclear unit.

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

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

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

•

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

•

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

•

compliance with mandatory reliability standards, including mandatory cyber security standards;

•

cyber intrusion;

•

labor disputes or shortages;

•

interruptions in fuel, water or material supplies;

•

terrorist attacks; or

•

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

    A severe drought could reduce the availability of water and restrict or prevent the operation of certain generating facilities. These or similar negative events could interrupt or limit electric generation or increase the cost of operating our facilities, which could have the effect of increasing the cost of electric service we

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provide to our members and affect their ability to perform their contractual obligations to us.

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

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

    We are exposed to the risk of changing prices for fuels, including coal, natural gas and uranium. We have taken steps to manage this exposure by entering into fixed or capped price contracts for some of our coal requirements. We have also entered into natural gas swap arrangements on behalf of some of our members designed to manage the exposure of those members to fluctuations in the price of natural gas. The operator of our nuclear plants manages price and supply risk through use of long-term fixed or capped price contracts with multiple vendors of uranium ore mining, conversion and enrichment services. However, these arrangements do not cover all of our and our members' risk exposure to increases in the prices of fuels. Therefore, increases in fuel prices could significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

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

    We obtain our fuel supplies, including coal, natural gas and uranium, from a number of different suppliers. Any disruptions in our fuel supplies, including disruptions due to weather, labor relations, environmental regulations, or other factors affecting our fuel suppliers, could result in us having insufficient levels of fuel supplies. For example, rail transportation bottlenecks could cause transportation companies to be unable to perform their contractual obligations to deliver coal on a timely basis which could result in lower than normal coal inventories at our coal-fired generating plants. Natural gas supplies can also be subject to disruption due to natural disasters and similar events. Any failure to maintain an adequate inventory of fuel supplies could require us to operate other generating plants at a higher cost or require our members to purchase higher-cost energy from other sources and affect their ability to perform their contractual obligations to us.

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

    Many of our generating facilities were constructed over 20 to 30 years ago and, even if maintained in accordance with good engineering practices, may require significant capital expenditures in order to maintain efficient and reliable operation. Potential operational issues associated with the age of the plants may lead to unscheduled outages, a generating facility being out of service for a period of time, or other service-related interruptions. Further, the adoption of new environmental regulations could lead to significant capital expenditures for our older generating facilities to comply with the new environmental requirements.

    These expenditures and service interruptions could have the effect of increasing the cost of electric service we provide to our members and, as a result, could affect their ability to perform their contractual obligations to us.

The financial difficulties faced by other companies could adversely affect us.

    We have exposure to many different industries and counterparties and routinely execute transactions with counterparties in the energy industry, such as coal and natural gas companies and the financial services industry, including commercial banks, investment banks and other institutions. Many of these transactions expose us to credit risk in the event of default of our counterparty. For example, we enter into hedge agreements to manage a portion of our exposure to fluctuations in the market price of natural gas with several counterparties. If our counterparties fail or refuse to honor their obligations, our hedges of the related risk may be ineffective. Any failure could significantly increase the cost of electric service we provide to our members.

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    Also, as a result of recent market events, some of our financial institution counterparties have experienced various degrees of financial distress, including liquidity constraints and credit downgrades. The financial distress of these counterparties may have an adverse effect on us in the event that these counterparties default or otherwise fail to meet their obligations to us.

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

    We depend primarily on revenue from our members under the wholesale power contracts to meet our financial obligations. Our members are our owners, and we do not control their operations or financial performance. Further, our members must forecast their load growth and power supply needs. If our members acquire more power supply resources than needed, whether from us or other suppliers, or fail to acquire sufficient supplies, our members' rates could increase excessively and affect financial performance. Also, as a result of recent economic conditions, sales by our members may not be sufficient to cover costs without rate increases, and our members may not collect all amounts billed to their consumers. Although each member has financial covenants to set rates to maintain certain margin levels, and our members' rates are not regulated by the Georgia Public Service Commission, pressure from their consumer members not to raise rates excessively could affect financial performance. Thus, we are exposed to the risk that one or more members could default in the performance of their obligations to us under the wholesale power contracts. Our ability to satisfy our financial obligations could be adversely affected if one or more of our members, particularly one of the larger members, defaulted on their payment obligations to us. Although the wholesale power contracts obligate non-defaulting members to pay the amount of any payment default pursuant to a pro rata step-up formula, there can be no guarantee that the non-defaulting members would be able to fulfill this obligation.

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

    Our business model is to provide our members with wholesale electric power at the lowest possible cost. Other technologies currently exist or are in development, such as fuel cells, microturbines, windmills and solar cells, that may in the future be capable of producing electric power at costs that are comparable with, or lower than, our cost of generating power. If these technologies were to develop sufficient economies of scale, the value of our generating facilities could be adversely affected.

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

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

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

ITEM 1B.  UNRESOLVED STAFF COMMENTS

    None.

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ITEM 2.  PROPERTIES

Generating Facilities

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

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Plant Performance

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

    The nuclear refueling cycle for Plants Hatch and Vogtle exceeds twelve months. Therefore, in some calendar years the units at these plants are not taken out of service for refueling, resulting in higher levels of equivalent availability and capacity factor.

Fuel Supply

    Coal.    Coal for Plant Wansley is currently purchased under term contracts and in spot market transactions, primarily from coal mines in the eastern United States. As of February 28, 2011, we had a 37-day coal supply at Plant Wansley based on continuous operation.

    Coal for Scherer Units No. 1 and No. 2 is purchased under term contracts and in spot market transactions. As of February 28, 2011, our coal stockpile at Plant Scherer contained a 39-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming.

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

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

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

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

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Co-Owners of Plants

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

Georgia Power Company

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

Municipal Electric Authority of Georgia

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

City of Dalton, Georgia

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

The Plant Agreements

Plants Hatch, Wansley, Vogtle and Scherer

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

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Dalton and us. The parties to each Ownership Agreement and Operating Agreement are referred to as "participants" with respect to each such agreement.

    In 1985, in four transactions, we sold our entire 60% undivided ownership interest in Scherer Unit No. 2 to four separate owner trusts established by institutional investors. We retained all of our rights and obligations as a participant under the Ownership and Operating Agreements relating to Scherer Unit No. 2 for the term of the leases. The leases include fair market value purchase options at specified dates. See Note 4 of Notes to Consolidated Financial Statements. (In the following discussion, references to participants "owning" a specified percentage of interests include our rights as a deemed owner with respect to our leased interests in Scherer Unit No. 2.)

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

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

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

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

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

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plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and No. 2, the participants have limited rights to disapprove such budgets proposed by Georgia Power and to substitute alternative budgets. The Ownership Agreements and Operating Agreements provide that, should a participant fail to make any payment when due, among other things, such nonpaying participant's rights to output of capacity and energy would be suspended.

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

    In conjunction with the development of additional units at Plant Vogtle (see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources"), we, Georgia Power, MEAG Power and the City of Dalton entered into amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, and entered into an Ownership Agreement that governs participation in Vogtle Units No. 3 and No. 4.

Rocky Mountain

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

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

    In late 1996 and early 1997, we entered into lease transactions for our 74.61% undivided ownership interest in Rocky Mountain. Under the terms of these transactions, we leased the facility to three institutional investors for the useful life of the facility, who in turn leased it back to us for a term of 30 years. We will continue to control and operate Rocky Mountain during the leaseback term. For more information about the structure of these lease transactions, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Off-Balance Sheet Arrangements – Rocky Mountain Lease Arrangements."

Doyle

    We have an agreement with Doyle I LLC, a limited liability company owned by one of our members, Walton EMC, to purchase the output of a gas-fired combustion turbine generating facility through May 15, 2015.

    During the term of the agreement, we have the right and obligation to purchase all of the capacity and energy from the facility. We are obligated to pay to Doyle I, LLC each month a capacity charge based on a performance rating and an energy charge equal to all costs of operating the facility. We are also obligated to

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pay the actual operation and maintenance costs and the costs of capital improvements. We are responsible for supplying all natural gas necessary to operate the facility. We have the right to dispatch the facility.

    Doyle I, LLC operates the facility. Doyle I, LLC must make the units available from May 15 to September 15 each year. Subject to air permit and other limitations, we may dispatch the facility at other times to the extent that the facility is available.

    We have an option to purchase the facility at the end of the term of the agreement at a fixed price. We account for this agreement as a capital lease of the facility for financial reporting purposes (see Note 4 of Notes to Consolidated Financial Statements).

ITEM 3.  LEGAL PROCEEDINGS

    We are a party to various actions and proceedings incidental to our normal business. Liability in the event of final adverse determinations in any of these matters is either covered by insurance or, in the opinion of our management, after consultation with counsel, should not in the aggregate have a material adverse effect on the our financial position or results of operations.

    For information about environmental matters that could have an effect on us, see Note 11 of Notes to Consolidated Financial Statements.

ITEM 4.  RESERVED

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PART II

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

    Not applicable.

ITEM 6.  SELECTED FINANCIAL DATA

    The following table presents our selected historical financial data. The financial data presented as of the end of and for each year in the five-year period ended December 31, 2010, has been derived from our audited financial statements. This data should be read in conjunction with "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and the "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."

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

Forward-Looking Statements and Associated Risks

    This annual report contains forward-looking statements, including statements regarding, among other items, (i) anticipated trends in our business, (ii) our future power supply requirements, resources and arrangements, (iii) our expected future capital expenditures and (iv) disclosures regarding market risk included in "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK." Some forward-looking statements can be identified by use of terms such as "may," "will," "expects," "anticipates," "believes," "intends," "projects," "plans" or similar terms. These forward-looking statements are based largely on our current expectations and are subject to a number of risks and uncertainties, some of which are beyond our control. For some of the factors that could cause actual results to differ materially from those anticipated by these forward-looking statements, see "RISK FACTORS." In light of these risks and uncertainties, we can give no assurance that events anticipated by the forward-looking statements contained in this annual report will in fact transpire.

Executive Overview

General

    We are a not-for-profit electric cooperative whose principal business is providing wholesale electric service to our 39 members. Consequently, substantially all of our revenues and cash flow are derived from sales to our members pursuant to long-term, take-or-pay wholesale power contracts that extend through 2050. These contracts obligate our members jointly and severally to pay all of our costs and expenses associated with owning and operating our power supply business. To that end, our existing rate structure provides for a pass-through of actual energy costs. Charges for fixed costs, including capacity, other non-energy charges, debt service obligations and the margin required to meet our budgeted margins for interest ratio are carefully managed throughout the year to ensure that sufficient capacity-related revenues are produced. This structure provides us with the ability to manage our revenues to assure full recovery of our costs in rates and has enabled us to consistently meet our financial obligations since our formation in 1974.

Expansion of Generation Capacity

    Over the last several years, we have focused our efforts on developing and acquiring various generation resources that offer our members greater ownership and control over their generation needs, through us, in order to mitigate their reliance on third-party contracts. To advance these efforts, we have taken the following actions:

•

We and the other co-owners of Plant Vogtle are developing two additional nuclear units at the Plant Vogtle site with an aggregate generating capacity of 2,200 megawatts. Each co-owner is maintaining the same percentage ownership in the new units as they have in the existing units which, for us, is a 30% undivided interest that will entitle us to approximately 660 megawatts of baseload generating capacity. The estimated total cost for our interest in the two new units, including allowance for funds used during construction, is approximately $4.2 billion, with planned commercial operation dates of 2016 and 2017. As of December 31, 2010, construction work in progress for this project was approximately $867 million.

•

In May 2009, we acquired the Hawk Road Energy Facility, a 500-megawatt peaking facility with three combustion turbines in Heard County, Georgia. The purchase price for the facility was $105 million. In addition, we assumed responsibility for an existing power purchase and sale agreement with seven of our members.

•

In October 2009, we acquired the Hartwell Energy Facility, a 300-megawatt oil and gas-fired peaking facility in Hart County, Georgia that consists of two combustion turbines. The purchase price for the facility was $148.5 million.

•

In April 2011, we expect to acquire KGen Murray I and II LLC, which owns a combined cycle facility with an aggregate generation capacity of 1,220 megawatts. This facility consists of two natural gas-fired combined cycle units and the purchase price, exclusive of working capital and other closing adjustments, is approximately $531 million.

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•

If we acquire the Murray facilities as expected, we will cancel the 605-megawatt combined cycle facility currently under development, which was projected to cost approximately $750 million.

•

We have also deferred the 100-megawatt Warren County biomass plant; however, we continue to monitor regulatory and legislative developments related to biomass electricity generation.

•

We and our members are currently evaluating additional gas-fired combustion turbine plants. Decisions regarding the acquisition or construction of these plants are expected to be made over the next two years.

    In connection with expanding our generation capacity, our total assets have increased to approximately $7.0 billion at December 31, 2010 from $5.0 billion at December 31, 2008, and our long-term debt has increased to nearly $4.8 billion from $3.4 billion during the same period. As we continue to expand our generation capacity, our assets and long-term debt will each continue to increase.

    In addition to expanding our generation resources, we forecast that expenditures required for existing generating facilities will be approximately $934 million through 2013, which includes normal additions and replacements to existing plants as well as required projects to maintain and achieve compliance with current and anticipated environmental requirements. Importantly, this forecast does not include capital expenditures or increased operational expenses for Plants Wansley and Scherer due to climate change or coal combustion by-products regulation likely to be adopted in the future.

2010 Financial Results

    Despite continued economic pressures, we are well positioned, both financially and operationally, to fulfill our obligations to our members, bondholders and creditors. In this regard, our revenues in 2010 were more than sufficient to recover all of our costs and to satisfy all of our debt service obligations and financial covenants, including the annual margin required to meet the margins for interest ratio rate covenant under the first mortgage indenture. Specifically, we recorded a net margin of $33.7 million in 2010, which met the 1.14 margins for interest ratio approved by our board of directors and exceeded the required margins for interest ratio of 1.10. We believe that it is important to increase our margin coverage in light of current financial market conditions and the period of increased capital requirements, as noted above. Consequently, beginning in 2009, we began targeting higher margins than necessary to meet the minimum margins for interest ratio of 1.10 required under the first mortgage indenture. For 2009 and 2010, we collected revenues sufficient to achieve margins for interest ratios of 1.12 and 1.14, respectively, effectively increasing our annual margins by 20% and 40%, respectively, over the minimum required level. In this regard, we recorded net margins of $33.7 million in 2010 and $26.4 million in 2009 as compared to net margins of $19.3 million for 2008. For 2011, we are again targeting a margins for interest ratio of 1.14. As our generation expansion program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to further increase or decrease the margins for interest ratio in the future.

Liquidity Position

    Our liquidity position is one of our most positive attributes contributing to our solid financial standing. Despite recent disruptions in the global financial markets, we maintained strong liquidity and, throughout the past two years as financial market conditions became more favorable, we strengthened our liquidity position. At December 31, 2010, we had $1.4 billion of unrestricted available liquidity. Our liquidity is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and commercial paper.

    Even though our current liquidity program has provided sufficient coverage during this acquisition and construction period, we continue to seek ways to further increase and build upon this credit strength as we approach the peak construction years. In this regard, we executed an unsecured indenture in December 2010 in order to increase financing options and expect to close on a $260 million term loan by April 2011 to provide interim financing for the acquisition of the KGen Murray facilities. Also, in the second quarter of 2011, we are planning a restructuring and related upsizing of several existing short-term credit facilities to provide sufficient coverage for our generation expansion program through 2017.

    In addition to maintaining more than adequate coverage for short-term credit needs, we have also taken advantage of historically low interest rates to secure

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favorable long-term financing for some of our construction and acquisition activity. RUS has approved loans to provide long-term funding for the Hawk Road and Hartwell facilities, and we have issued $850 million of taxable first mortgage bonds to finance a portion of our costs associated with the additional units at Plant Vogtle. We have also executed a conditional commitment letter with the Department of Energy to secure a long-term loan guarantee for up to 70%, or $3.057 billion, of eligible project costs for the additional units at Plant Vogtle.

Outlook for 2011

    We remain focused on providing reliable, cost-effective energy to our members and the 4.1 million people they serve. There are, nevertheless, certain risks and challenges that we must address, including:

•

Continued ability to access financial markets to support our significant future capital requirements;

•

General economic conditions in the U.S. and the related impacts on our members and their consumers;

•

Managing the effects of increased environmental regulation of fossil fuel-fired power plants, most likely leading, for example, to more stringent controls for emissions of carbon dioxide or other emissions, or disposal of coal combustion by-products, particularly at Plants Wansley and Scherer; and

•

Fuel cost volatility, including related transportation costs.

    We believe that we continue to be well positioned to provide reliable, cost-effective energy to our members and their consumers. As we manage our risks, we intend to keep doing what we have done so successfully for the last 37 years, including, among other things:

•

Maintaining a balanced diversity of generating resources – primarily nuclear, coal, natural gas and hydro;

•

Working with our members to evaluate new resources, including, where feasible, renewable resources, to be acquired or developed and owned by us to help meet our members' power supply requirements; and

•

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

Summary of Cooperative Operations

Margins and Patronage Capital

    We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. Revenues in excess of current period costs in any year are designated as net margin in our statements of revenues and expenses. Retained net margins are designated on our balance sheets as patronage capital, which is allocated to each of our members on the basis of its fixed percentage capacity costs responsibilities in our generation and purchased power resources. Since our formation in 1974, we have generated a positive net margin in each year and had $596 million in patronage capital and membership fees as of December 31, 2010. Our equity ratio, calculated as patronage capital and membership fees divided by total capitalization and long-term debt due within one year, was 10.4% at December 31, 2010 and 10.8% at December 31, 2009.

    Patronage capital constitutes our principal equity. Any distributions of patronage capital is subject to the discretion of our board of directors. However, under the 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 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 not less than 30% of our total long-term debt and equities.

Rates and Regulation

    Pursuant to the wholesale power contracts between us and each of our members, we are required to design capacity and energy rates that generate revenues

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sufficient to recover all costs, including the payments of principal and interest on our indebtedness, to establish and maintain reasonable margins and to meet the financial coverage requirements under the first mortgage indenture.

    The rate schedule under the wholesale power contracts assigns on a long-term basis, the responsibility for our fixed costs to each of our members. The monthly charges for capacity and other non-energy charges are based on a rate formula using our budget. Energy charges are based on actual energy costs, including fuel costs, variable operations and maintenance costs, and purchased energy costs.

    Under the first mortgage indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates that are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The margins for interest ratio is determined by dividing margins for interest by interest charges. Margins for interest equals the sum of (i) our net margins (after certain defined adjustments), (ii) interest charges and (iii) any amount included in net margins for accruals for federal or state income taxes. The definition of 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 such 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 such losses or expenditures. The interest charges in the margins for interest ratio is comprised of interest on debt secured under our first mortgage indenture.

    We review our financial results frequently throughout the year, and with board approval, make budget adjustments when and as necessary to ensure that we generate revenues sufficient to recover all costs and to meet our budgeted margins for interest ratio. In the event we were to fall short of the minimum 1.10 margins for interest ratio required under the first mortgage indenture at year end, the rate schedule includes a prior period adjustment mechanism designed to recover the shortfall without any additional action by our board of directors. Amounts, if any, by which we fall short of the minimum 1.10 margins for interest ratio would be accrued as of December 31 of the applicable year and collected from our members during the period April through December of the following year.

    In 2008 we achieved a margins for interest ratio of 1.10. However, to enhance margin coverage during the period of generation facility construction and acquisition, our board of directors approved budgets for 2010 and 2009 to achieve a 1.14 and 1.12 margins for interest ratio (above the minimum 1.10 required by the first mortgage indenture). As a result, we achieved a margins for interest ratio of 1.14 in 2010 and 1.12 in 2009. Our board of directors approved a budget for 2011 to achieve a 1.14 margins for interest ratio. As our construction and acquisition program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to change the targeted margins for interest ratio in the future, although not below the 1.10 margins for interest ratio required under our first mortgage indenture.

    Under the first mortgage indenture and related loan contract with the Rural Utilities Service, adjustments to our rates to reflect changes in our budgets are generally not subject to Rural Utilities Service approval. Changes to the rate schedule under the wholesale power contracts are generally subject to Rural Utilities Service approval. Our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

Accounting Policies

Basis of Accounting

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

Critical Accounting Policy

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

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    We are subject to the provisions of the Financial Accounting Standards Board (FASB) authoritative guidance issued regarding Regulated Operations. The guidance permits us to record regulatory assets and regulatory liabilities to reflect future cost recoveries or refunds, respectively, that we have a right to pass through to our members. At December 31, 2010, our regulatory assets and liabilities totaled $311 million and $114 million, respectively. While we do not currently foresee any events such as competition or other factors that would make it not probable that we will recover these costs from our members as future revenues through rates under our wholesale power contracts, if such an event were to occur, we could no longer apply the provisions of accounting for Regulated Operations, which would require us to eliminate all regulatory assets and liabilities that had been recognized as a charge to our statement of revenues and expenses and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, we would be required to determine any impairment to other assets, including plants, and write-down those assets, if impaired, to their fair value.

New Accounting Pronouncements

    In January 2010, the FASB issued Fair Value Measurements and Disclosures – Improving Disclosures about Fair Value Measurements. The new guidance provides for improved disclosure requirements about fair value measurements and requires a reporting entity to disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers. The guidance also clarifies that fair value measurement disclosures are required for each asset class. In the reconciliation for fair value measurements using significant unobservable inputs (Level 3), the standard also requires a reporting entity to present separately information about purchases, sales, issuances, and settlements (that is, on a gross basis rather than as one number). We adopted this new guidance beginning with the quarter ended March 31, 2010 except that the requirement to present Level 3 activity separately is not effective for us until the quarter ending March 31, 2011. The adoption of the standard did not have a material effect on our disclosures.

    Effective January 1, 2010, we adopted FASB standard for Accounting for Transfers of Financial Assets – an amendment of Accounting for Transfers for Servicing of Financial Assets and Extinguishments of Liabilities. The standard requires improved disclosures about transfers of financial assets and removes the exception from applying consolidation of variable interest entities to qualifying special purpose entities. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.

    Effective January 1, 2010, we adopted FASB standard Amendments to Consolidation of Variable Interest Entities. The standard provides new consolidation guidance for variable interest entities and requires a company to assess the determination of the primary beneficiary of a variable interest entity based on whether the company has the power to direct matters that most significantly impact the activities of the entity, and the obligation to absorb losses or the right to receive benefits of the entity. The standard also requires ongoing reassessments of whether a company is the primary beneficiary of a variable interest entity. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.

    In February 2010, the FASB amended its authoritative guidance related to subsequent events to alleviate potential conflicts with current SEC guidance. Effective immediately, these amendments remove the requirement that a SEC filer disclose the date through which it has evaluated subsequent events. The adoption of this guidance did not have a material impact on our disclosure.

Results of Operations

Operating Revenues

    Sales to Members.    We generate revenues principally from the sale of electric capacity and energy.

•

Capacity revenues are derived primarily from electric capacity sales to our members under the wholesale power contracts. The members have contractually agreed to pay us for the electric capacity they obtain from us to meet their operating requirements. We receive capacity revenues whether or not our generation assets, including power purchase contracts, are dispatched to produce electricity.

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•

Energy revenues are earned by selling electricity to our members, which involves generating or purchasing electricity for our members.

    Our kilowatt-hour sales to our members, one of the primary drivers of our operating revenues, fluctuate from period to period based on several factors, including weather and other seasonal factors, load requirements in the service territories of our members, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

    Total revenues from sales to members increased by 13.0% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and decreased 7.6% for the year ended December 31, 2009 compared to the year ended December 31, 2008. The components of member revenues were as follows:

    Capacity revenues relate primarily to the assignment to each of the members of the fixed costs, including fixed production expenses, depreciation and amortization expenses and interest charges associated with our business. Each member is required to pay us for capacity furnished under its wholesale power contract in accordance with rates we establish.

    Capacity revenues from members increased 5.5% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and increased 8.5% for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in capacity revenues in 2010 compared to 2009 resulted partly from an increase in operations and maintenance expenses due to higher costs incurred at Plants Hatch and Vogtle, higher depreciation expenses at Plants Scherer and Wansley related to capital expenditures for environmental compliance projects, higher net interest charges due to increased amortization of debt discount and expense for costs associated with the Hartwell acquisition and supplemental credit enhancement for Rocky Mountain, and an increase in the margins for interest ratio to 1.14 in 2010 compared to 1.12 in 2009. These increases were offset somewhat by a decrease in purchase power capacity costs attributable to the Hartwell acquisition. The increase in capacity revenues in 2009 compared to 2008 is primarily due to higher interest expense on long-term debt relating to environmental capital expenditures for existing coal-fired facilities that have now been placed in service and to an increase in the margins for interest ratio to 1.12 in 2009 compared to 1.10 in 2008. For further discussion regarding operation and maintenance, depreciation and amortization and purchased power, see "– Operating Expenses"; for further discussions regarding amortization of debt discount and expense, see "– Interest Charges".

    Energy revenues relate primarily to the pass-through to our members of the variable costs, such as fuel costs, variable operation and maintenance costs and purchased energy costs, associated with our business. Each member is required to pay us for energy we furnish it under its wholesale power contract, in accordance with rates we establish.

    Energy revenues from members increased 22.5% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and decreased 22.3% for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in energy revenues for 2010 as compared to 2009 was primarily due to the pass-through of higher fuel costs associated with increased coal-fired generation at Plants Scherer and Wansley. The decrease in energy revenues was primarily due to the pass-through to our members of lower fuel costs (primarily due to lower levels of coal-fired generation) in 2009 as compared to 2008 and lower purchased power energy costs (primarily due to the lower volume of purchased megawatt-hours). In addition, natural gas-fired generation costs decreased due to a substantial drop in market prices for natural gas. For a discussion of fuel costs and purchased power costs, see "– Operating Expenses."

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

    For the year ended December 31, 2010 compared to the year ended December 31, 2009, kilowatt-hour sales to members increased 12.1% and for the year ended December 31, 2009 as compared to the year ended December 31, 2008, kilowatt-hour sales to members decreased 13.4%. The average revenue per kilowatt-hour from sales to members increased 0.7% for 2010 compared to 2009 and increased 6.7% for 2009 compared to 2008. An increase in kilowatt-hours of generation was the primary reason for increased kilowatt-hours sold to members in 2010. Decreases in kilowatt-hours of generation and kilowatt-hours of purchased power were the reasons for decreased kilowatt-hours sold to members in 2009. For further discussions regarding fuel and purchased power costs, see "– Operating Expenses."

    We pass through actual energy costs to our members such that energy revenues equal energy costs. The energy portion of member revenues per kilowatt-hour increased 9.3% for the year ended December 31, 2010 as compared to the year ended December 31, 2009 and decreased 10.3% for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in average revenues per kilowatt-hour in 2010 compared to 2009 is primarily due to the pass-through of higher fuel costs. The decrease in average energy revenues per kilowatt-hour in 2009 compared to 2008 is primarily due to the pass-through of lower fuel costs and lower purchased power energy costs. For further discussion regarding fuel costs and purchased power costs, see "– Operating Expenses."

Operating Expenses

    Our operating expenses increased 14.5% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and were 11.6% lower for the year ended December 31, 2009 compared to the year ended December 31, 2008. The increase in 2010 as compared to 2009 was primarily due to higher fuel costs, production costs and deprecation and amortization, offset somewhat by lower purchased power costs. The decrease in 2009 as compared to 2008 was primarily due to lower fuel costs and lower purchased power costs, offset somewhat by an increase in depreciation expense.

    Total fuel costs increased 33.6% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and decreased 22.7% for the year ended December 31, 2009 as compared to the year ended December 31, 2008 while total generation increased 13.6% and decreased 10.1% for the same periods, respectively. Average fuel cost per kilowatt-hour increased 17.6% in 2010 compared to 2009 and decreased 14.0% in 2009 compared to 2008. The increase in total and average fuel costs for 2010 as compared to 2009 resulted primarily from a 27.0% increase in higher cost coal-fired generation at Plants Scherer and Wansley. The increase in generation was due to significantly less scheduled outage time in 2010 as compared to 2009. The 2009 outages were primarily related to environmental compliance projects. For 2009, the decrease in total fuel costs resulted primarily from lower coal-fired generation at Plants Scherer and Wansley. In addition, total fuel costs at the natural gas-fired Chattahoochee energy facility decreased as well due to substantially lower market prices for natural gas. The 2009 decrease in total and average fuel costs resulted primarily from a 26.7% decrease in coal-fired generation at Plants Scherer and Wansley due to increased scheduled outage time in 2009 compared to 2008. Coal-fired generation has a higher average cost per kilowatt-hour of generation than nuclear generation. Natural gas-fired generation at the Chattahoochee energy facility increased 54.9%, or 779,000 megawatt-hours in 2009, primarily as a result of a substantial decline in the price of natural gas; the average fuel cost per megawatt-hour of natural gas-fired generation at Chattahoochee decreased 55.1% from prior year levels.

    Production expenses increased 16.3% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and increased 2.4% for the year ended December 31, 2009 as compared to the year ended December 31, 2008. For 2010 as compared to 2009, the increase in production expenses resulted partly to increased general operations and maintenance expenses Plants Hatch and Vogtle and partly due to operations and maintenance expenses for Hawk Road and Hartwell incurred in 2010. We acquired Hawk

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Road and Hartwell in May and October of 2009, respectively.

    Purchased power costs decreased 36.0% for the year ended December 31, 2010 as compared to the year ended December 31, 2009 and decreased 23.1% for the year ended December 31, 2009 compared to the year ended December 31, 2008 as follows:

    The decrease in purchased power capacity costs for the years 2008 through 2010 was primarily as a result of our acquisition of Hartwell in October 2009. As part of the acquisition, we acquired an existing power purchase agreement we had with the former owners of Hartwell. Our acquisition of Hartwell means we are now responsible for all expenses related to the operation and maintenance of the facility. See Note 12 of Notes to Consolidated Financial Statements for more information.

    Purchased power energy costs decreased 26.3% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and decreased 28.7% for the year ended December 31, 2009 compared to the year ended December 31, 2008. Purchased kilowatt-hours decreased 46.5% in 2010 compared to 2009 and decreased 55.6% for 2009 compared to 2008. The average cost of purchased power energy per kilowatt-hour increased 19.6% in 2010 compared to 2009 and increased 60.6% in 2009 compared to 2008. The decrease in purchased power energy costs for the year ended December 31, 2010 compared to the same period of 2009 resulted from (i) a decrease in kilowatt-hours acquired under our energy replacement program, which replaces power from our owned generation facilities with lower price spot market purchased power energy, (ii) lower realized losses incurred for natural gas financial contracts utilized for managing exposure to fluctuations in the market prices of natural gas and (iii) no power purchases under the Hartwell power purchase agreement in 2010 as a result of our acquisition of Hartwell. For the year ended December 31, 2009 compared to the same period of 2008, changes in purchased power energy costs, volume of kilowatt-hours acquired and average cost per kilowatt-hour were affected by the following items: (i) reduced purchased power energy costs from the lower volume of purchased kilowatt-hours and the increase in the cost per kilowatt-hour purchased were primarily due to the expiration of the Morgan Stanley purchased power agreement effective December 31, 2008, (ii) a lower average price per kilowatt-hour realized under our energy replacement program, and (iii) realized losses incurred in 2009 for natural gas swap agreements we utilized to manage exposure to fluctuations in the market price of natural gas. The realized losses related to the natural gas swaps were somewhat offset the reduction in purchased power energy costs discussed in (i) and (ii) above.

    Depreciation and amortization expense increased 8.6% for the year ended December 31, 2010 compared to the year ended December 31, 2009 and increased 11.9% for the year ended December 31, 2009 as compared to the year ended December 31, 2008. The increases in depreciation and amortization in 2010 compared to 2009 and for 2009 compared to 2008 were primarily due to increased depreciation expense for Plants Scherer and Wansley related to capital expenditures for environmental compliance projects that were placed in service during 2009. Also, depreciation expense related to Hawk Road, acquired in 2009, contributed to the increase. For information regarding Hawk Road, see Note 12 of Notes to Consolidated Financial Statements.

    Accretion expense totaled $17.1 million for the year ended December 31, 2010, $18.3 million for the year ended December 31, 2009 and $17.1 million for the year ended December 31, 2008. The accretion expense recognized under accounting for Asset Retirement Obligations, primarily relates to our nuclear generation facilities.

Interest Charges

    Interest on long-term debt and capital leases increased by 8.4% for the year ended December 31, 2010 compared to the same period of 2009 and increased 12.6% for the year ended December 31, 2009 compared to the same period of 2008. The increase in 2010 was primarily due to the issuance in November 2009 and November 2010 of $400 million and $450 million, respectively, in taxable fixed rate bonds for the purpose of financing construction of Plant Vogtle Units No. 3 and No. 4. The 2009 increase was primarily due to the issuance in February 2009 of $350 million in taxable fixed rate bonds for general working capital purposes.

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    Other interest increased for the year ended December 31, 2010 compared to the same period of 2009 primarily due to new credit facilities commitment fees. These new credit facilities were closed on in late 2009 and early 2010. Other interest was lower for the year ended December 31, 2009 compared to the year ended December 31, 2008 primarily due to interest incurred on short-term borrowings during 2008.

    Allowance for debt funds used during construction increased by 115.0% for 2010 compared to 2009 and by 57.8% for 2009 compared to 2008 primarily due to construction expenditures for Plant Vogtle Units No. 3 and No. 4.

    Amortization of debt discount and expense increased 26.5% for the year ended December 31, 2010 compared to the same period of 2009 and 23.6% for the year ended December 31, 2009 compared to the same period of 2008 partly due to amortization of issuance costs associated with transactions that closed in May and August 2009 to provide supplemental credit enhancement for the Rocky Mountain lease arrangements and partly due to the amortization of losses on debt refinancings associated with the Hartwell acquisition.

Net Margin

    Our net margin for the years ended December 31, 2010, 2009 and 2008 was $33.7 million, $26.4 million and $19.3 million, respectively. These amounts produced respective margins for interest ratio of 1.14, 1.12 and 1.10, each greater than or equal to the minimum required under the first mortgage indenture. Our margin requirement is based on a ratio applied to interest charges. 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. Our non-cash capital credits allocation from Georgia Transmission was $1.7 million for 2010, $1.5 million for 2009 and $1.4 million for 2008.

    To continue to enhance our financial coverage during a period of generation facility construction and acquisition, our board of directors approved a budget for 2011 to achieve margins for interest ratio of 1.14, above the minimum 1.10 ratio required by the first mortgage indenture. For additional information on our margin requirement, see "– Summary of Cooperative Operations – Rates and Regulation." For additional information on our generation facility construction, see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources."

Financial Condition

Overview

    Our financial condition remains stable.

    In keeping with our budgeted margin for 2010, we achieved a 1.14 margins for interest ratio which produced a net margin of $33.7 million. This caused a corresponding increase in patronage capital (our equity), resulting in total patronage capital and membership fees of $596 million at December 31, 2010.

    The minimum margins for interest ratio required under the first mortgage indenture is 1.10. However, to enhance margin coverage during the period of generation expansion, our board of directors approved a 1.14 margins for interest ratio for 2010 and has also approved a 1.14 margins for interest ratio for 2011. As our generation expansion program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to further increase, or decrease, the margins for interest ratio in the future.

    Although we have increased our margins for interest coverage, due to the amount of new debt we issued in 2010, the majority of which relates to the Plant Vogtle Units No. 3 and No. 4 construction, our equity to total capitalization ratio decreased from 10.8% at December 31, 2009 to 10.4% at December 31, 2010. While the absolute level of margins and patronage capital are increasing, our equity ratios will continue to decrease during the peak years of generation expansion. After the generation expansion program is completed, we expect our equity ratio to start an upward trend.

    We had a strong liquidity position at December 31, 2010, with $1.4 billion of unrestricted available liquidity, including $672 million of cash.

    Our total assets increased to $7.0 billion at December 31, 2010 from $6.4 billion at December 31, 2009. The majority of this increase relates to (i) an increase in total utility plant in connection with the construction of Plant Vogtle Units No. 3 and No. 4, and (ii) higher cash balances as a result of new debt financings related to the Plant Vogtle construction and funds received under the member power bill prepayment program.

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    We maintained adequate access to capital throughout 2010, issuing more than $580 million of long-term debt in the capital markets. We also issued commercial paper at historically low rates averaging less than 0.4%, which provided a low-cost source of interim funding for the Plant Vogtle construction and for the Hawk Road and Hartwell acquisitions. See "– Financing Activities" for a discussion of the permanent financing for these facilities.

    There was a net increase in long-term debt of $528 million at December 31, 2010 compared to December 31, 2009. The significant net increase was due to the issuance of $450 million of first mortgage bonds to fund the Plant Vogtle construction and $150 million of funds advanced under Rural Utilities Service-guaranteed loans. The average interest rate on the $4.8 billion of long-term debt outstanding at December 31, 2010 was 5.2%.

    Property additions totaled $669 million and were financed with a combination of funds from operations and short-term and long-term borrowings. The property additions related to purchases of nuclear fuel, normal additions and replacements to existing generation facilities, environmental control facilities being installed at one of our coal-fired generation facilities and construction of new generation facilities.

Liquidity and Sources of Capital

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

    We have historically obtained the majority of our long-term financing from Rural Utilities Service-guaranteed loans funded by the Federal Financing Bank. However, Rural Utilities Service-guaranteed funding for new generation facilities is uncertain and may be limited at any point in the future due to budgetary and political pressures faced by Congress. Also, over the next ten years the loan demand of electric cooperatives is projected to exceed Rural Utilities Service-guaranteed funding authorization levels unless there is an increase over current levels of funding. The President's budget for fiscal year 2011, which has not been adopted, proposed to reduce funding by almost 40% from 2010 levels and, in support of the President's commitment to reduce inefficient fossil-fuel subsidies, would prohibit loans for new or existing fossil-fueled generation. The proposal would limit the use of electric loan funds to renewable energy, transmission, distribution and carbon-capture projects on generation facilities. The President's budget proposal for fiscal year 2012 provides for $6 billion in guaranteed loans – a reduction of less than 10% from 2010 levels. The same restrictions as proposed for 2011 would apply, except that up to $2 billion would be 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 assurances that it will continue to do so. Because of these factors, we cannot predict the amount or cost of Rural Utilities Service-guaranteed loans that may be available to us in the future. See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with the Rural Utilities Service."

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

    Therefore, any generation facilities that we may build in the future will likely be financed long-term through a variety of sources, which could include Rural Utilities Service-guaranteed loans funded through the Federal Financing Bank, publicly or privately offered debt financings (both taxable and tax-exempt) and other financing sources.

    In connection with a loan program established pursuant to Title XVII of the Energy Policy Act of 2005, the Department of Energy has offered us a conditional term sheet under a federal loan guarantee program for up to 70% of eligible project costs, not to exceed $3.057 billion, related to our 30% participation in the two new nuclear units at Plant Vogtle.

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

    Liquidity.    At December 31, 2010, we had $1.4 billion of unrestricted available liquidity to meet short-term cash needs and liquidity requirements, consisting of $672 million of cash and cash equivalents and $705 million of unused and available committed short-term credit arrangements. Our liquidity position at December 31, 2010 has increased from December 31, 2009 due to higher cash balances in connection with (i) the member power bill prepayment program, and (ii) proceeds received from a first mortgage bond issuance in November 2010.

    Net cash provided by operating activities was $230 million in 2010, and averaged $255 million for the three year period 2008 through 2010.

    At December 31, 2010, we had in excess of $1 billion of committed credit arrangements in place comprised of six separate facilities as reflected in the table below:

    Despite the turmoil in the credit and financial markets that began in 2007, we have been able to maintain a robust liquidity position over the last several years due to the strong relationships we have with the banks in our credit facilities. We are seeing indications that the cost of credit, while not at 2007 levels, is becoming less expensive and more readily available, and we anticipate that we will continue to meet our liquidity goals in 2011.

    We are using our short-term credit arrangements to provide interim funding for (i) payments to Georgia Power related to the construction of Plant Vogtle Units No. 3 and No. 4, (ii) Hawk Road and Hartwell, and (iii) initial engineering and design work related to the Warren County biomass facility and a 605 megawatt combined cycle facility. For a discussion of the generation projects under development, see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources." For a discussion of the Hawk Road and Hartwell acquisitions, see Notes 12(a) and 12(b), respectively, of Notes to Consolidated Financial Statements.

    In connection with the anticipated acquisition of the Murray facilities in April 2011, we plan to close on a $260 million three-year term loan with three banks to provide interim financing for a portion of the cost of acquiring the facilities. The remaining $271 million of the acquisition cost will be financed on an interim basis with some combination of cash and draws under our existing short-term credit arrangements.

    For a discussion of our plans regarding permanent financing for Plant Vogtle Units No. 3 and No. 4, Hawk Road, Hartwell and the Murray facilities, see "– Financing Activities."

    Several of our line of credit facilities contain a similar financial covenant that requires us to maintain minimum patronage capital levels. Currently, we are required to maintain minimum patronage capital of $545 million. As of December 31, 2010 our actual patronage capital was $596 million. An additional covenant contained in several of our credit facilities limits our secured indebtedness to $8.5 billion and unsecured indebtedness to $4.0 billion. At December 31, 2010, we had approximately $4.8 billion of secured indebtedness outstanding and $306 million of unsecured indebtedness outstanding.

    Under the $250 million line of credit with National Rural Utilities Cooperative Finance Corporation (CFC), we have the option of converting any amounts outstanding under the line of credit to a term loan with a maturity no later than December 31, 2043. Any amounts drawn under this line of credit, as well as any amounts converted to a term loan, will be secured under the first mortgage indenture.

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    Under the commercial paper program we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit, thereby providing 100% dedicated support for any commercial paper outstanding. We periodically assess our needs to determine the appropriate amount of commercial paper backup to maintain and currently have in place a $475 million committed backup credit facility provided by eight banks as shown in the table below:

    Along with the lines of credit from CoBank, CFC and JPMorgan Chase Bank, funds may also be advanced under the backup line of credit supporting commercial paper for general working capital purposes. In addition, under certain of our committed lines of credit we have the ability to issue letters of credit totaling $450 million in the aggregate. However, any amounts related to issued letters of credit will reduce the amount available to draw as working capital under those facilities. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under the commercial paper backup line for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue.

    Between projected cash on hand and the credit facilities currently in place, we believe we have sufficient liquidity to fund our generation construction program and to cover normal operations through 2011. However, in order to further enhance our liquidity position during the peak years of generation expansion, we are currently planning a restructuring and related upsizing of certain of our short-term credit facilities, including the commercial paper backup credit facility, in the second quarter of 2011.

    In December 2008, we instituted a power bill prepayment program to provide for an additional source of liquidity. Under the program, members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. The discount is comparable to our avoided cost of borrowing. Since the program began, we have received a total of $313 million in power bill prepayments from the seventeen members who have participated in the program, including $97 million received in 2010. At December 31, 2010, the balance remaining to be applied against future power bills was $112 million.

    In addition to unrestricted available liquidity, we had $103 million of restricted liquidity at December 31, 2010, including (i) $97 million in restricted short-term investments pursuant to deposits made into a Rural Utilities Service Cushion of Credit Account, and (ii) $6 million in restricted cash relating to proceeds from our issuance of clean renewable energy bonds on deposit with a bank. The deposits in the Cushion of Credit Account were made voluntarily and earn a guaranteed rate of interest of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service on Rural Utilities Service notes and Rural Utilities Service-guaranteed Federal Financing Bank notes. On January 3, 2011, we applied $44 million against FFB debt service payments due, leaving a balance of $53 million in the Cushion of Credit Account. From time to time we may deposit additional funds into the Cushion of Credit Account. We anticipate that the $6 million of clean renewable energy bond proceeds will be drawn down over the next two years. See "– Financing Activities" for further discussion of these financings.

    Liquidity Covenants.    At December 31, 2010, we had only one financial agreement in place containing a liquidity covenant. This covenant is in connection with the Rocky Mountain lease transactions and requires us to maintain minimum liquidity of $50 million at all times during the term of the lease. We had sufficient liquidity to meet this covenant in 2010 and expect to have sufficient liquidity to meet this covenant in 2011.

Financing Activities

    First Mortgage Indenture.    Our first mortgage debt is secured equally and ratably under the first mortgage indenture by a lien on substantially all of our tangible

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and some of our intangible assets, including those we acquire in the future. The mortgaged property includes our electric generating plants and some of our contracts for the purchase, sale or transmission of electricity of more than one year in duration or that relate to the ownership, operation, construction or maintenance of our electric generation facilities. In 2010, Hawk Road and Hartwell became part of the mortgaged property under our first mortgage indenture.

    Indenture for Unsecured Debt Securities.    In December 2010, we put in place an indenture for unsecured debt securities to provide an additional financing alternative. Its most likely use would be in connection with interim financing for construction of new generation facilities or for generation facilities we may acquire. We have no unsecured debt securities outstanding, and we have no plans to issue any unsecured debt securities at this time.

    Bond Financings.    In March 2010, the Development Authority of Burke County, Georgia and the Development Authority of Monroe County, Georgia issued, on our behalf, $134 million of variable rate tax-exempt pollution control revenue bonds for the purpose of refunding $134 million of pollution control bonds issued by the development authorities on our behalf in 2006. This tax-exempt debt is secured under the first mortgage indenture.

    In November 2010, we issued $450 million of fixed rate first mortgage bonds. The bonds were issued for the purpose of financing a portion of the cost of constructing Plant Vogtle Units No. 3 and No. 4 (including redeeming commercial paper issued in connection with the construction of these new nuclear units). These bonds are secured under the first mortgage indenture.

    We have a program in place under which we are refinancing, on a continued tax-exempt basis, the annual principal maturities of pollution control bonds originally issued on our behalf by the Development Authority of Monroe County, Georgia. The refinancing of these pollution control bonds' principal maturities allows us to preserve a low-cost source of financing. To date, we have refinanced approximately $300 million under this program, including $12 million of principal that matured in January 2011. We have board approval to continue this refinancing program covering an additional $12 million of pollution control bond principal maturing in January 2012.

    In late March 2011, we are planning to close on a refinancing transaction pursuant to which the Development Authority of Appling County, Georgia, the Development Authority of Burke County, Georgia and the Development Authority of Monroe County, Georgia will issue, on our behalf, $180 million of term rate pollution control revenue bonds for the purpose of refunding $180 million of pollution control bonds previously issued by the development authorities on our behalf. This tax-exempt debt will be secured under the first mortgage indenture.

    Rural Utilities Service-Guaranteed Loans.    We currently have five approved Rural Utilities Service-guaranteed loans, funded through the Federal Financing Bank, totaling $1.2 billion that are in various stages of being drawn down, with $907 million remaining to be advanced. Included in the five approved loans are loans for the Hawk Road and Hartwell acquisitions, both of which were approved in September 2010.

    We have four loan applications pending with the Rural Utilities Service, including loan applications for general improvements, for the Warren County biomass facility, for the 605 megawatt combined cycle facility and for the acquisition of the Murray facilities. If the Murray acquisition closes as anticipated, we will withdraw the loan application for the 605 megawatt combined cycle facility as this project will be cancelled as a result of the acquisition. Due to the previously announced indefinite delay of our Warren County biomass project, there is no anticipated approval date for that loan application. We expect action on the general improvements loan later in 2011 and on the Murray loan in 2013.

    Although the President's budget proposals for fiscal years 2011 and 2012 would prohibit Rural Utilities Service funding for new or existing fossil-fueled generation facilities, we will continue to submit loan applications for such facilities to the extent Rural Utilities Service regulations in place at the time we submit the applications allow us to do so. In that regard, should members subscribe to any additional natural-gas fired combustion turbine facilities, we anticipate filing loan applications for these facilities as well. See "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources" for a discussion of our participation in new generation facilities. See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with the Rural Utilities Service" for a

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discussion of the Rural Utilities Service's current position relating to funding of new generation facilities.

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

    Department of Energy-Guaranteed Loans.    The Department of Energy loan guarantee program was authorized pursuant to Title XVII of the Energy Policy Act of 2005, which is intended to support the commercialization of innovative technologies to reduce air pollutants, including greenhouse gases. Pursuant to this program, in May 2010 we signed a conditional term sheet with the Department of Energy that sets forth the general terms of a loan and related loan guarantee that would fund approximately 70% of the estimated $4.2 billion cost to construct our 30% undivided share of Plant Vogtle Units No. 3 and No. 4, not to exceed $3.057 billion. The loan structure would entail a loan that is expected to be funded by the Federal Financing Bank carrying a federal loan guarantee provided by the Department of Energy, with the debt secured under our first mortgage indenture.

    We are working with the Department of Energy to finalize the loan guarantee. However, final approval and issuance of a loan guarantee by the Department of Energy is subject to receipt of the combined construction permits and operating licenses for Plant Vogtle Units No. 3 and No. 4 from the Nuclear Regulatory Commission, negotiation of definitive agreements, completion of due diligence by the Department of Energy and satisfaction of other conditions. Therefore, there can be no assurance that the Department of Energy will ultimately issue the loan guarantee to us. We anticipate that any Plant Vogtle costs not funded under the Department of Energy loan guarantee program would be financed through the issuance of taxable bonds.

    Of the approximately $1.2 billion of currently estimated project costs not expected to be funded under the Department of Energy loan guarantee program, we have already financed $850 million through the issuance of first mortgage bonds. We expect to issue another approximately $400 million of first mortgage bonds for this purpose in the fourth quarter of 2011.

Capital Requirements

    Capital Expenditures.    As part of our ongoing capital planning, we forecast expenditures required for generating facilities and other capital projects. The table below details these expenditure forecasts for 2011 through 2013. Actual expenditures may vary from the estimates listed in the table because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor.

    In addition to the amounts reflected in the table above, we expect to incur capitalized costs of approximately $1.3 billion by 2017 to complete construction of Plant Vogtle Units No. 3 and No. 4. For information about steps we have taken to procure financing for the Plant Vogtle project, see "– Financing Activities."

    If we acquire the Murray facilities as anticipated in April 2011, we will revise our plans to construct future generation resources to reflect this additional generation capacity and our members' projected power supply needs. In that regard, we would cancel our previously announced combined cycle plant currently under development. Independently of this acquisition, we have deferred the 100 megawatt Warren County biomass plant; however, we continue to monitor regulatory and legislative developments related to biomass electricity generation. The capital expenditure table above does not include expenditures for either the combined cycle or biomass plants. To-date, the expenditures on the combined cycle and biomass plants have not been material.

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    We have identified and are evaluating other generation resource development opportunities that we could pursue to meet our members' future energy needs, including certain quantities of combustion turbine facilities. These options, which are subject to future member subscription for specific projects, are not included in the capital expenditures table above (see "BUSINESS – OUR POWER SUPPLY RESOURCES – Future Power Resources"). Additional projects that we may ultimately construct, if any, as well as the cost of construction, are not known at this time.

    We are currently subject to extensive environmental regulations and may be subject to future additional environmental regulations, including future implementation of existing laws and regulations. Since alternative legislative and regulatory environmental compliance programs continue to be debated on a national level (particularly in relation to climate change), it is difficult to predict what capital costs may ultimately be required.

    Environmental compliance projects already completed include a selective catalytic reduction system and a flue gas desulfurization project at Plant Wansley, and a mercury removal project at Plant Scherer.

    Environmental compliance projects currently underway include the installation of flue gas desulfurization equipment and a selective catalytic reduction system at Plant Scherer, both expected to be in-service by 2014. To complete these projects, we expect to spend an additional approximately $14 million beyond what is reflected in the capital expenditure table above.

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

    For additional information regarding environmental regulation, see "BUSINESS – ENVIRONMENTAL AND OTHER REGULATION."

    Contractual Obligations.    The table below reflects, as of December 31, 2010, our contractual obligations for the periods indicated.

Inflation

    As with utilities generally, inflation has the effect of increasing the cost of our operations and construction program. Operating and construction costs have been less affected by inflation over the last few years because rates of inflation have been relatively low. While we cannot predict what level of inflation may occur in the future, in light of current U.S. financial policies, the potential for inflationary pressures exist.

Credit Rating Risk

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

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    We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable collateral. Our primary exposure to potential collateral postings is at rating levels of BBB-/Baa3 or below. As of December 31, 2010, our maximum potential collateral requirements were as follows:

    At senior secured rating levels:

•

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

•

a total of approximately $191 million at a senior secured level of BB+/Ba1 or below, and

    At senior unsecured or issuer rating levels:

•

a total of approximately $224,000 at a senior unsecured or issuer rating level of BBB-/Baa3,

•

a total of approximately $1.7 million at a senior unsecured or issuer rating level of BB+/Ba1 or below.

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

    Given our current level of ratings, our management does not have any reason to expect a downgrade that would result in credit ratings below the rating triggers contained in any of our financial and contractual agreements. However, our ratings reflect only the views of the rating agencies, and therefore we cannot give any assurance that our ratings will be maintained at current levels for any period of time.

Off-Balance Sheet Arrangements

    We are liable for certain contractual obligations for which other parties are primarily liable, and we would be expected to pay only if the other parties fail to satisfy such obligations. These obligations are not shown on our balance sheet and are described below.

    Georgia Transmission Debt Assumption.    In connection with our corporate restructuring in 1997 in which we sold our transmission related assets to Georgia Transmission (which represented 16.86% of our assets), Georgia Transmission assumed 16.86% of the then outstanding indebtedness associated with pollution control bonds pursuant to an assumption agreement and an indemnity agreement. If Georgia Transmission fails to satisfy its obligations under this debt assumption, we remain liable for any unsatisfied amounts. In that event, we would be entitled to reimbursement from Georgia Transmission for any amounts we paid. At December 31, 2010, the total obligation assumed by Georgia Transmission relating to outstanding pollution control bond principal was $94 million. Georgia Transmission plans to refund $54 million of its assumed debt on its mandatory tender date of April 1, 2011, and then the remaining $40 million of assumed debt on its mandatory tender date of April 1, 2012 based solely on its own credit and not as a joint obligation with us. Assuming this plan is carried out, as of April 1, 2011 the amount of assumed debt will decrease to $40 million, and as of April 1, 2012 there will no longer be any assumed debt outstanding. Georgia Transmission's estimated payments of principal and interest in 2011 pursuant to this assumed obligation are approximately $5 million.

    Rocky Mountain Lease Arrangements.    In December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to six separate owner trusts (referred to as the head leases) for the benefit of three investors (referred to as owner participants) for a term equal to 120% of the estimated useful life of Rocky Mountain, in exchange for one-time rental payments aggregating $794 million made at the time the leases were entered into. Each owner participant, through its related owner trust, funded a portion of its payment to us through an equity contribution (in the aggregate totaling $171 million), and financed the remaining portion through a loan from a bank. Immediately following the head leases to the

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owner trusts, the owner trusts leased their undivided interests in Rocky Mountain to our wholly owned subsidiary, Rocky Mountain Leasing Corporation (RMLC), for a term of 30 years under six separate leases, referred to as the facility leases. RMLC then subleased the undivided interests back to us for an identical term also under six separate leases, referred to as the facility subleases.

    We used a portion of the one-time rental payments paid to us by the owner trusts to acquire the capital stock of RMLC and to make a $698 million capital contribution to RMLC. RMLC in turn used the capital contribution to fund six payment undertaking agreements (in the aggregate totaling $641 million) with Rabobank Nederland (referred to as the payment undertaker) and six equity funding agreements (in the aggregate totaling $57 million) with AIG Matched Funding Corp. that provide for these third parties to pay all of:

•

RMLC's periodic basic rent payments under the facility leases; and

•

the fixed purchase price of the undivided interests in Rocky Mountain at the end of the terms of the facility leases if we cause RMLC to exercise its option to purchase these interests at that time.

    As a result of these lease transactions, after making the capital contribution to RMLC, we had $92 million remaining of the amount paid by the owner trusts which we used to prepay Federal Financing Bank indebtedness while retaining possession of, and entitlement to, our portion of the output of Rocky Mountain.

    The facility subleases require us to make semi-annual rental payments to RMLC. In turn, RMLC is required to make identical rental payments to the owner trusts under the facility leases. In 2010, the amount of the rental payments under the facility subleases and facility leases each totaled $58 million. The payment undertaking agreements require the payment undertaker to pay the rent payments directly to the owner trust's lender in satisfaction of RMLC's rent payment obligation under the facility leases and the applicable owner trust's repayment obligation under the loans used to finance a portion of the one-time rental payments to us described above. Because RMLC funds these rent payments through the payment undertaking agreements, RMLC returns to us, in the form of a patronage dividend, amounts received by it pursuant to the facility subleases other than amounts RMLC requires to fund its annual operating expenses. RMLC remains liable for all rental payments under the facility leases (and would not be able to make such patronage dividend to us) if the payment undertaker fails to make such payments, although the owner trusts have agreed to use due diligence to pursue the payment undertaker before pursuing payment from RMLC or us.

    The senior unsecured debt obligations of Rabobank are rated AAA by S&P and Aaa by Moody's. RMLC has the right to replace Rabobank as the payment undertaker with substitute credit protection of certain approved governmental or other entities, including banks or financial institutions rated at least AA by S&P and Aa2 by Moody's; provided that any replacement therefore is subject to approval by the owner participants in accordance with their internal credit policies and guidelines. If, as a result of replacing the payment undertaker, the lender requests a higher interest rate on the loans, RMLC will be required to find a replacement lender to purchase the loan certificates from the lender unless the owner participants consent to such increase in the interest rate.

    AIG Matched Funding Corp. is a wholly owned subsidiary of American International Group, Inc. (AIG) and AIG has guaranteed the obligations of AIG Matched Funding Corp. under the equity funding agreements. At the time the lease transactions were entered into, AIG's senior unsecured debt obligations were rated AAA by S&P and Aaa by Moody's. The equity funding agreements provide that if AIG fails to maintain a credit rating of at least AA from S&P and Aa2 from Moody's, then AIG Matched Funding Corp. will be required to post collateral having a stipulated credit quality to secure its obligations thereunder.

    In September 2008, AIG's ratings fell below the collateralization threshold. As a result, AIG Matched Funding Corp. posted collateral in compliance with the equity funding agreements, consisting of securities issued by an instrumentality of the United States government that are rated AAA in an amount equal to 105% of the net present value of its future payment obligations related to the equity portion of the fixed purchase price (equity portion of the fixed purchase price was $124 million at December 31, 2010). In accordance with the terms of the equity funding agreements, the market value of the posted collateral (other than cash) is determined weekly by an independent third party and AIG Matched Funding Corp. is required to post additional collateral to the

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extent that it is determined that the market value of such collateral, together with the cash collateral (if any), has fallen below the required collateral amount as discussed above. According to U.S. Bank National Association, which as collateral agent holds the collateral and provides the weekly valuation thereof, the market value of the collateral was $130 million at December 31, 2010.

    If AIG fails to comply with its collateralization obligations or fails to maintain a credit rating of at least BBB- from S&P and Baa3 from Moody's, then RMLC must, within 60 days of becoming aware of such fact, enter into replacement equity funding agreements with a financial institution that has credit ratings of at least AA from S&P and Aa2 from Moody's. If such replacement is triggered by AIG's failure to provide sufficient collateral, RMLC would have the right to terminate the equity funding agreements at the higher of market value or accreted value (as determined in each case). However, if AIG is rated below BBB- from S&P and below Baa3 from Moody's, but AIG Matched Funding Corp. is in compliance with its collateralization requirement, RMLC would not have a right to terminate the equity funding agreements in connection with a replacement. AIG's ratings are currently A- from S&P and Baa1 from Moody's. In the event that RMLC is not able to enter into replacement equity funding agreements, then RMLC may be required to purchase the owner trusts' equity interests from the owner participants.

    The operative agreements relating to the Rocky Mountain lease transactions also require us to maintain surety bonds with a surety bond provider that meets minimum credit rating requirements to secure certain of our payment obligations under the Rocky Mountain lease transactions. Accordingly, we entered into a surety bond arrangement with AMBAC Assurance Corporation concurrently with the consummation of the Rocky Mountain lease transactions.

    The operative agreements relating to the Rocky Mountain lease transactions provide that if the surety bond provider fails to maintain a credit rating of at least AA from S&P or Aa2 from Moody's, then we must, within 60 days of becoming aware of such fact, provide (i) a replacement surety bond from a surety bond provider that has such credit ratings, (ii) a letter of credit from a bank with such credit ratings, (iii) other acceptable credit enhancement or (iv) any combination thereof. In the event that we are unable to obtain replacement credit enhancement, then we may be required to purchase the owner trusts' equity interests from the owner participants.

    In November 2008, AMBAC's credit ratings fell below the minimum threshold, triggering our obligation to provide replacement credit enhancement. In two separate transactions that closed in May 2009 (relating to five of the leases) and in August 2009 (relating to the sixth lease), we entered into agreements with Berkshire Hathaway Assurance Corporation pursuant to which Berkshire is providing supplemental credit enhancement to the credit enhancement provided by AMBAC, thereby satisfying our obligation to provide replacement credit enhancement.

    Berkshire is currently rated AA+ by S&P and Aa1 by Moody's. As with AMBAC, if Berkshire is downgraded below AA by S&P and Aa2 by Moody's, we will be obligated to replace, within 60 days of becoming aware of that fact, the Berkshire surety bonds for all six of the lease transactions with other qualified credit enhancement. With regard to the sixth lease transaction only, we have an obligation to replace Berkshire surety bonds with other qualified credit enhancement if (i) federal legislation is enacted which imposes a tax on reimbursement payments that may be owed to Berkshire by either us or AMBAC under this lease transaction, and (ii) Berkshire elects to terminate its surety bond in connection with the enactment of such legislation. During 2009, legislation of the type referred to above was introduced in each of the House of Representatives and Senate. If this or similar legislation is enacted, Berkshire would have a right to terminate its surety bond in the sixth lease transaction but not in any of the other five lease transactions. This would in turn trigger our obligation to provide replacement credit enhancement within 60 days for the sixth lease transaction. The enactment of this legislation would make it difficult for us to find other qualified credit enhancement.

    As our wholly owned subsidiary, the financial condition and results of operations of RMLC are fully consolidated into our financial statements. The equity funding agreements and corresponding lease obligations are reflected on our balance sheets as Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions ($124 million at December 31, 2010 and $116 million at December 31, 2009). However, our financial statements do not reflect the payment undertaking agreements or the corresponding

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lease obligations, or the payments made by the payment undertaker, including the payments of rent under the facility leases and facility subleases, because they have been extinguished for financial reporting purposes. If RMLC's interests in the payment undertaking agreements and the corresponding lease obligations were reflected on our balance sheets at December 31, 2010, both the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions would have been higher by $709 million. However, it would have no effect on our statements of operations or cash flows.

    The assets of RMLC, including the payment undertaking agreements and the equity funding agreements, are not available to pay our creditors or our affiliates' creditors.

    At the end of the term of each facility lease, we have the option to cause RMLC to purchase any owner trust's undivided interests in Rocky Mountain at fixed purchase option prices that aggregate $1.087 billion for all six facility leases. The payment undertaking agreements and equity funding agreements would fund $715 million and $372 million of this amount, respectively, and these amounts would be paid to the owner trusts over five installments in 2027. If we do not elect to cause RMLC to purchase any owner trust's undivided interest in Rocky Mountain, Georgia Power has an option to purchase that undivided interest. If neither we nor Georgia Power exercise our purchase option, and we return (through RMLC) any undivided interest in Rocky Mountain to an owner trust, that owner trust has several options it can elect, including:

•

causing RMLC and us to renew the related facility leases and facility subleases for up to an additional 16 years and provide collateral satisfactory to the owner trusts,

•

leasing its undivided interest to a third party under a replacement lease, or

•

retaining the undivided interest for its own benefit.

    Under the first two of these options we must arrange new financing for the outstanding amount of the loans used to finance the owner trusts' one-time rental payments described above. The aggregate amount of the outstanding loans to all of the owner trusts at the end of the term of the facility leases is anticipated to be $666 million. If new financing cannot be arranged, the owner trusts can ultimately cause us to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the loan certificates or cause RMLC to exercise its purchase option or RMLC and us to renew the facility leases and facility subleases, respectively.

    If option one above is chosen, at the end of the 16-year lease renewal term, the facility leases and facility subleases terminate, the owner trusts take possession of Rocky Mountain at whatever its value and operating condition may be at such time, with no residual value guaranty.

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ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

    The Dodd-Frank Wall Street Reform and Consumer Protection Act enacted in July 2010 could impact our use of over-the-counter derivatives. Regulations to implement the Dodd-Frank Act could impose additional requirements on the use of over-the-counter derivatives, such as margin and reporting requirements, which could affect both the use and cost of over-the-counter derivatives. The impact, if any, cannot be determined until regulations are finalized.

    For additional information regarding our rate structure, see "BUSINESS – OGLETHORPE POWER CORPORATION – Electric Rates."

    We have an executive risk management committee that provides general oversight over all risk management activities, including commodity trading, fuels management, insurance procurement, debt management and investment portfolio management. This committee is comprised of our chief executive officer, chief operating officer, chief financial officer and the executive vice president, member and external relations. The risk management committee has implemented comprehensive risk management policies to manage and monitor credit and market price risks. These policies also specify controls and authorization levels related to various risk management activities. The committee frequently meets to review corporate exposures, risk management strategies, and hedge positions. The audit committee of our board of directors receives regular reports on corporate exposures, risk management activities and the actions of the risk management committee. For further discussion of our board of director's oversight of risk management, see "DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE – Board of Directors' Role in Risk Oversight."

Interest Rate Risk

    At December 31, 2010, we were exposed to the risk of changes in interest rates related to our $869 million of variable rate debt, including $306 million of commercial paper outstanding (which typically has maturities of between 1 and 90 days) and $563 million of pollution control bond debt outstanding (including weekly rate bonds, auction rate securities subject to repricing every 35 days and term rate bonds subject to repricing from March 2011 through March 2012). At December 31, 2010, the weighted average interest rate on this variable rate debt was 1.5%. If, within the next twelve months, interest rates on this debt changed a hypothetical 100 basis points on the respective repricing dates and remained at that level for the remainder of the year, annual interest expense would change by approximately $9 million.

    Our objective in managing interest rate risk is to maintain a balance of fixed and variable rate debt that will lower our overall borrowing costs within reasonable risk parameters. As part of this debt management strategy we have a general guideline of having between 15% and 30% variable rate debt to total debt. At December 31, 2010, we had 17% of our total debt, including commercial paper and capital lease debt, in a variable rate mode.

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

    Due to the significant amount of new long-term debt we anticipate incurring in connection with our new generation projects (including the two facilities acquired in 2009 as well as the construction of Plant Vogtle Units No. 3 and No. 4), we will have increased risk associated with interest rates in general. If we are in a rising interest rate environment at the time we issue new debt for these projects (whether it be Federal Financing Bank debt or publically issued bonds), the higher level of interest rates will increase our costs.

    We continue to analyze and consider using various types of derivative products (including swaps, caps, floors and collars) to help manage our interest rate risk, but do not currently have any in place.

Capital Leases

    In December 1985, we sold and subsequently leased back from four purchasers our 60% undivided

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ownership interest in Scherer Unit No. 2. The capital leases provide that our rental payments vary to the extent of interest rate changes associated with the debt used by the lessors to finance their purchase of undivided ownership shares in the unit. The debt currently consists of $9 million in serial facility bonds due June 30, 2011 with a 6.97% fixed rate of interest.

    We entered into a power purchase and sale agreement with Doyle I, LLC to purchase all of the output from a five-unit gas-fired generation facility. The Doyle agreement is reported on our balance sheet as a capital lease. The lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00%. At December 31, 2010, the weighted average interest rate on the lease obligation was 6.06%.

Equity Price Risk

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

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

    The investment guidelines for equity securities typically limit the type of securities that may be purchased and the concentration of equity holdings in any one issuer and within any one sector. With respect to fixed-income securities, the investment guidelines set forth limits for the type of bonds that may be purchased, state that investments be primarily in securities with an assigned investment grade rating of BBB- or above and establish that the average credit quality of the portfolio typically be A+/A1 or higher.

    A 10% decline in the value of the internal and external funds' equity securities as of December 31, 2010 would result in a loss of value to the funds of approximately $18 million. For further discussion on our nuclear decommissioning trust funds, see Note 1 of Notes to Consolidated Financial Statements.

Commodity Price Risk

Coal

    We are also exposed to the risk of changing prices for fuels, including coal and natural gas. We have interests in 1,501 megawatts of coal-fired nameplate capacity at Plants Scherer and Wansley. We purchase coal under term contracts and in spot-market transactions. Some of our coal contracts provide volume flexibility and most have fixed or capped prices. We anticipate that our existing contracts and stockpiles will provide fixed prices for nearly 100% of our remaining forecasted coal requirements for 2011 and fixed or capped prices for approximately 63% of our forecasted coal requirements in 2012.

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

Natural Gas

    We own four gas-fired generation facilities totaling 1,886 megawatts of nameplate capacity. (See "PROPERTIES – Generating Facilities.")

    We also have a power purchase contract with Doyle I, LLC (treated as a capital lease) under which approximately 325 megawatts of nameplate capacity and associated energy is supplied by gas-fired facilities. (See "BUSINESS – OUR POWER SUPPLY RESOURCES – Power Purchase and Sale Arrangements – Power Purchases" and "PROPERTIES – Generating Facilities.") Under this

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contract, we are exposed to variable energy charges, which incorporate the facility's actual operation and maintenance and fuel costs. We have the right to purchase natural gas for Doyle and exercise this right to actively manage the cost of energy supplied from this contract and the underlying natural gas price and operational risks.

    In providing operation management services for Smarr EMC, we purchase natural gas, including transportation and other related services, on behalf of Smarr EMC and ensure that the Smarr facilities have fuel available for operations. (See "BUSINESS – OUR MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources" and "PROPERTIES – Generating Facilities" and "– Fuel Supply.")

    We manage exposure to fluctuations in the market price of natural gas for 14 of our members who have elected to participate in our natural gas hedging program. This program layers in fixed prices over a rolling eight-quarter time horizon using natural gas swap arrangements for a portion of the forecasted gas requirements related to the gas-fired resources that we manage and/or operate. Under these swap agreements, we pay the counterparty a fixed price for specified natural gas quantities and receive a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. If the natural gas swaps had been terminated on December 31, 2010, we would have made a net payment of approximately $2.1 million. As of December 31, 2010, approximately 16% of our 2011 total system forecasted natural gas requirements (including requirements for the Smarr facilities) were hedged under swap arrangements. A hypothetical 10% decline in the market price of natural gas would have resulted in a decrease of approximately $1.9 million to the fair value of our natural gas swap agreements. Effective April 1 of each year, additional members may elect to participate in our natural gas hedging program. Members may choose to discontinue receiving these natural gas price management services at any time.

Changes in Risk Exposure

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

    In April 2011, we expect to acquire the gas-fired Murray facilities with an aggregate generation capacity of 1,220 megawatts. The planned acquisition of these facilities is expected to increase our exposure to natural gas. We are not aware of any other facts or circumstances that would significantly impact these exposures in the near future; however, nonperformance by one of our hedge counterparties may increase our exposure to market volatility.

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ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index To Financial Statements

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES
For the years ended December 31, 2010, 2009 and 2008

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2010 and 2009

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED BALANCE SHEETS
December 31, 2010 and 2009

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION
December 31, 2010 and 2009

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
For the years ended December 31, 2010, 2009 and 2008

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND
ACCUMULATED OTHER COMPREHENSIVE DEFICIT
For the years ended December 31, 2010, 2009 and 2008

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the years ended December 31, 2010, 2009 and 2008

     1. Summary of significant accounting policies:

a. Business description

    Oglethorpe Power Corporation is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, GA. We are owned by 39 retail electric distribution cooperative members in Georgia. The wholesale electric power we provide consists of a combination of generating units totaling 5,594 megawatts of nameplate capacity. Our members in turn distribute energy on a retail basis to approximately 4.1 million people.

    In December 2009, Flint EMC became our 39^th member. Flint did not have a percentage capacity responsibility from any of our generation resources in 2010; however, it has the right to participate in any future generation resources we may acquire or construct.

b. Basis of accounting

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

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

    The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2010 and 2009 and the reported amounts of revenues and expenses for each of the three years in the period ended December 31, 2010. Actual results could differ from those estimates.

c. Patronage capital and membership fees

    We are organized and operate as a cooperative. Our members paid a total of $195 in membership fees. Patronage capital includes retained net margin. Any excess of revenue over expenditures from operations is treated as advances of capital by our members and is allocated to each of them on the basis of their percentage capacity responsibility.

    Any distributions of patronage capital are subject to the discretion of our board of directors, subject to first mortgage indenture requirements. Under the first mortgage indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our long-term debt and equities.

d. Accumulated comprehensive deficit

    The table below provides detail regarding the beginning and ending balance for each classification of other comprehensive deficit along with the amount of any reclassification adjustments included in margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit. Our

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

e. Margin policy

    We are required under the first mortgage indenture to produce a margins for interest ratio of at least 1.10. For the years 2010, 2009 and 2008, we achieved a margins for interest ratio of 1.14, 1.12 and 1.10, respectively.

f. Operating revenues

    Operating revenues consist primarily of electricity sales pursuant to long-term wholesale power contracts which we maintain with each of our members. These wholesale power contracts obligate each member to pay us for capacity and energy furnished in accordance with rates we establish. Energy furnished is determined based on meter readings which are conducted at the end of each month. Actual energy costs are compared, on a monthly basis, to the billed energy costs, and an adjustment to revenues is made such that energy revenues are equal to actual energy costs.

    Operating revenues from non-members consisted primarily of off-system sales to third parties.

    The following table reflects members whose revenues accounted for 10% or more of our total operating revenues in 2010, 2009 and 2008:

g. Receivables

    Substantially all of our receivables are related to electricity sales to our members. The receivables are recorded at the invoiced amount and do not bear interest. Our members are required through the wholesale power contracts to reimburse us for all costs. The remainder of our receivables are primarily related to transactions with affiliated companies, electricity sales to non-members and to interest income on investments. Uncollectible amounts, if any, are identified on a specific basis and charged to expense in the period determined to be uncollectible.

h. Nuclear fuel cost

    The cost of nuclear fuel, including a provision for the disposal of spent fuel, is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2010, 2009 and 2008 amounted to approximately $65,916,000, $52,163,000, and $48,987,000, respectively.

    Contracts with the U.S. Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power Company, as agent for the co-owners of the plants, is pursuing legal remedies against the Department of Energy for breach of contract. An on-site dry storage facility for Plant Hatch is operational and can be expanded to accommodate spent fuel through the life of the plant. Sufficient storage capacity is available at Plant Vogtle in the spent fuel pools to maintain full core discharge capacity for both units into 2014.

    On July 9, 2007, the U.S. Court of Federal Claims found in favor of Southern Company and awarded damages in the amount of $59,900,000 for Plant Hatch and Plant Vogtle. Our share of the award is $17,980,000. The decision has been appealed by the Department of Energy. No amounts have been recognized in the financial statements as of December 31, 2010. The final outcome of this matter cannot be determined at this time. Our rate-making treatment of any such future award received would be passed on to our members.

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i. Asset retirement obligations

    The accounting and reporting for asset retirement obligations are done under the authoritative guidance related to Asset Retirement Obligations. The liability recognized primarily relates to our nuclear facilities. We also recognized retirement obligations for ash ponds, landfill sites and asbestos removal.

    Under the accounting provisions for Regulated Operations, we may record an offsetting regulatory asset or liability to reflect the difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes for both the cumulative effect of adoption and for future period timing differences. There was no cumulative effect to net margin resulting from the adoption of accounting for Asset Retirement Obligations. We estimate an annual decrease of approximately $1,900,000 over the next several years to the regulatory asset.

    Accounting for Asset Retirement Obligations does not permit non-regulated entities to accrue future retirement costs associated with long-lived assets for which there are no legal obligations to retire. In accordance with regulatory treatment of these costs, we continue to recognize the retirement costs for these other obligations in depreciation rates. These costs are reflected on the balance sheet as "Accumulated retirement costs for other obligations" under the caption "Deferred credits and other liabilities."

    In December 2009, Georgia Power provided us with revised asset retirement obligations studies associated with decommissioning at Plants Hatch and Vogtle. The studies were based on the completed plant decommissioning cost estimates and were in accordance with the standards defined in the accounting guidance related to Asset Retirement Obligations. The 2009 studies resulted in a change in the cash flow estimates of nuclear decommissioning costs as noted in the following table.

    The following tables reflect the details of the Asset Retirement Obligations included in the balance sheets for the years 2010 and 2009.

    As previously discussed, we defer the timing differences between cost recognition under the accounting guidance for Asset Retirement Obligations and cost recovery for ratemaking purposes. Increases and decreases to the regulatory asset are reflected on the accompanying balance sheets as "Deferred asset associated with retirement obligations."

    Consistent with our ratemaking, unrealized gains and losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset or liability.

j. Nuclear decommissioning trust fund

    The Nuclear Regulatory Commission requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. We have established external trust funds to comply with the Nuclear Regulatory Commission's regulations. The funds set aside for decommissioning are managed and invested in accordance with applicable requirements of our board of directors and the Nuclear Regulatory Commission. Funds are invested in a diversified mix of equity and fixed income securities. At December 31, 2010 and 2009, equity securities comprised 57% and 55% of the external funds and fixed income securities comprised 43% and 45%, respectively. The Nuclear Regulatory Commission's minimum external funding

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requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. We have filed plans with the Nuclear Regulatory Commission to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the Nuclear Regulatory Commission. We also maintain internal reserves that can be transferred to the external trust fund as needed. All realized gains, losses and earned income associated with the nuclear decommissioning fund are reflected within the "Cash flows from operating activities" and "Cash flows from investing activities" sections, respectively, of the cash flow statement. Purchases, including reinvestments of earned income, and sales are reflected in the "Activity in decommissioning fund" line of the "Cash flows from investing activities" section of the cash flow statement. For the periods ending December 31, 2010 and 2009, realized gains and (losses) totaled $20,647,000 and ($663,000), respectively.

    Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service. The 2009 site study received from Georgia Power resulted in a decrease in the estimated cost of decommissioning Plants Hatch and Vogtle. Actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Information with respect to our portion of the estimated costs of decommissioning co-owned nuclear facilities is as follows:

    We have not recorded any provision for decommissioning during the years 2010, 2009 and 2008 because the balance in the decommissioning trust fund at December 31, 2010 is expected to be sufficient to fund the nuclear decommissioning obligation in future years. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.4%. We assume a 6.0% earnings rate for our decommissioning trust fund assets. Since inception (1990) to 2010, the nuclear decommissioning trust fund has produced a return in excess of 7.0%. Notwithstanding the results of the revised site studies, our management believes that any increase in cost estimates of decommissioning can be recovered in future rates.

k. Depreciation

    Depreciation is computed on additions when they are placed in service using the composite straight-line method. Annual depreciation rates, as approved by the Rural Utilities Service, in effect in 2010, 2009 and 2008 were as follows:

    Depreciation expense for the years 2010, 2009 and 2008 was $144,715,000, $133,235,000, and $119,067,000, respectively. In 2009, the Nuclear Regulatory Commission granted 20-year license extensions for Plant Vogtle Units No. 1 and No. 2.

l. Electric plant

    Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction. The cost of equity and debt funds is calculated at the embedded cost of all such funds. For the years ended 2010, 2009 and 2008, the allowance for funds used during construction rates were 5.73%, 5.54% and 6.10%, respectively.

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

m. Cash and cash equivalents

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

n. Restricted cash

    The restricted cash balance at December 31, 2010 consisted of $6,300,000 of clean renewable energy bond proceeds on deposit with CoBank to fund a qualifying project at the Rocky Mountain Pumped Storage Hydroelectric facility. At December 31, 2009, restricted cash consisted of $10,940,000, utilized in January of 2010 for payment of principal on certain pollution control bonds, and $11,465,000 of clean renewable energy bond proceeds on deposit with CoBank.

o. Restricted short-term investments

    At December 31, 2010 and 2009, we had $97,286,000 and $80,590,000, respectively, on deposit with the Rural Utilities Service in the Cushion of Credit Account. The restricted funds will be utilized for future Rural Utilities Service/Federal Financing Bank debt service payments. The deposit earns interest at a Rural Utilities Service-guaranteed rate of 5% per annum.

p. Inventories

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

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

    At December 31, 2010 and 2009, fossil fuels inventories were $54,348,000 and $101,993,000, respectively. Inventories for spare parts at December 31, 2010 and 2009 were $117,467,000 and $107,844,000, respectively.

q. Deferred charges

    We account for both coal-fire outage and nuclear refueling outage costs as deferred outage costs. Coal-fired outage costs, which are accounted for as regulatory assets, are deferred and subsequently amortized on a straight-line basis to expense over an 18 to 24-month period. Nuclear refueling outage costs, which are accounted for as regulatory assets, are deferred and subsequently amortized on a straight line basis to expense over the 18-month and 24-month operating cycles of each unit.

    We account for debt issuance costs as deferred debt expense. Deferred debt expense is amortized to expense on a straight-line basis over the life of the respective debt issues, which approximates the effective interest rate method.

    Premium and loss on reacquired debt represents premiums paid, together with any unamortized transaction costs, related to reacquired debt. This deferred charge is amortized in equal monthly amounts over the amortization period for the refunding debt.

    As of December 31, 2010, the remaining amortization periods for deferred outage costs, debt issuance costs and premium and loss on reacquired debt range from approximately 1 to 32 years.

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