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

FORM 10-K

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

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

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

20092010 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 207209 employees.

    In December 2009, Flint EMC, which withdrew as a member in January 2005, became our 39^th member. Currently, Flint does not have a percentage capacity responsibility from 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 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 atwww.opc.com.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, this annual report on Form 10-K and information contained on this website 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

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payment of principal and interest on our indebtedness.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 hydro.water. (See "OUR POWER SUPPLY RESOURCES" and"PROPERTIES – Generating Facilities.")

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    In 2009,2010, three of our members, Cobb EMC, Jackson EMC and Sawnee EMC, accounted for 15.0%14.5%, 11.6% and 10.2%10.6% of our total revenues, respectively. Each of our other members accounted for less than 10% of our total revenues in 2009.2010.

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 costscost 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 costscost 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 2009,2010, we supplied energy that accounted for approximately 55%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

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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.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:

•

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

•

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

•

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 costscost 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 20092010 and 20102011 to achieve a 1.12 and 1.14 margins for interest ratio, respectively; each above the minimum 1.10 ratio required by the first mortgage indenture. As our generation construction and acquisition program evolves, our board of directors will continue to evaluate the level of margin coverage and may choose to further increase, or decrease,change the targeted margins for interest ratio in the future.

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    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 have also purchasedpurchase 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-based rates.cost.

    As of December 31, 2009,2010, we had approximately $8.0$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

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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, proposeswhich 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, prohibitswould prohibit loans for new or existing fossil-fueled generation. The budget limitsproposal 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,

•

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

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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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additional 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, currentcertain legislative proposals includehave 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 wouldcould be available to us or our members under the currentcertain 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.

    Effective January 1, 2005, one of our members, Flint, withdrew from membership in us and assigned, with our consent, its wholesale power contract to Cobb EMC. A portion of the power supply resources covered by the Flint wholesale power contract was reallocated to six other members. Cobb also acquired Pataula EMC and provided us a guarantee of Pataula's payment obligations under its wholesale power contract. Other members could consider similar arrangements.

    In December 2009, Flint again became one of our members. For further discussion regarding Flint, see " – General."

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 2009,2010, we supplied approximately 55%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 treataccount 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 2009,2010, 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 the Hawk Road Energy Facility 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 2017.2017, 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. This amendment, which the parties agreed is subject2010 to the approval of the Georgia Public Service Commission, replacesreplace 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

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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 permanently 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 2006, Southern Nuclear Operating Company, on behalf of the Owners, filed an application with the Nuclear Regulatory Commission for early site permits for these two additional units, and in March 2008 filed an application for combined construction permits and operating licenses for two 1,100 megawatt units, using the Westinghouse AP1000 technology.

    Five entities intervened in the Plant Vogtle early site permit process. The Nuclear Regulatory Commission appointed an Atomic Safety and Licensing Board panel to rule on the contentions of the intervenors. After a hearing in March 2009, the Atomic Safety and Licensing Board panel found in favor of the Owners and the Nuclear Regulatory Commission, and against the intervenors.

    In August 2009, the Nuclear Regulatory Commission issued thean 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 October 2009, the intervenors in the aforementioned litigation filed a petition for reviewMarch 2008, Southern Nuclear Operating Company, on behalf of the early site permit decision inOwners, filed an application for combined construction permits and operating licenses for two 1,100 megawatt units, using the United States Court of Appeals for the District of Columbia.

Westinghouse AP1000 technology. An Atomic Safety and Licensing Board panel was also 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 Board admitted one contentionAdvisory Committee on Reactor Safeguards also issued a letter in January 2011 endorsing the issuance of intervenorsthe license for hearing.Units No. 3 and No. 4. The Nuclear Regulatory Commission schedule for this proceeding contemplates a decision in fourth quarterlate 2011.

    In August 2009, the Nuclear Regulatory Commission issued letters to Westinghouse revising the review schedules needed to certify the AP 1000 standard design for new reactors and expressing concerns related to the availability of adequate information and the shield building design. The shield building protects the containment and provides structural support to the containment cooling water supply. Southern Nuclear is continuing to work with Westinghouse and the Nuclear Regulatory Commission to resolve these concerns. Any possible delays in the AP 1000 design certification schedule, including those addressed by the Nuclear Regulatory Commission in their letters, are not currently expected to affect the projected commercial operation dates for Plant Vogtle Units No. 3 and No. 4.

    Our estimated total costs for the new units, including allowance for funds used during construction, are approximately $4.2 billion. WeAs 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 havehad subscribed for a 100 megawatt biomass-fueled generating plant. We have acquired a site in Warren County, Georgia, and are currently in the process of conductingconducted preliminary engineering work and environmental analyses, acquiringand requested proposals for major equipment and requesting proposals for an engineering, procurement and construction contract. This plant iswas 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 iswas $477 million, including allowance for funds during construction. We haveconstruction and we submitted a loan application to the Rural Utilities Service for financing of this project.project in the event development is resumed. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF

legislation that could include a national renewable electricity standard, which would begin at 6% of retail sales in 2012, increase to 20% in 2020, and remain at that level through 2039. While we will not be subject to the annual renewable electricity standard – it would apply only to retail electric suppliers that sell at least 4,000,000 megawatt hours of electricity to retail consumers – initially two of our members would be subject to the standard. We are currently pursuing the construction of a 100 megawatt renewable biomass power generation facility in Georgia that we believe would qualify under the bill's renewable electricity standard. Senate legislation and initiatives, like the Clean Energy Jobs and American Power Act of 2009, the American Clean Energy Leadership Act of 2009 and the Kerry – Lieberman – Graham framework could produce results similar to H.R. 2454. We cannot predict at this time whether any legislative actionslegislation will result in a renewable electricity standard applicable to our members or in the regulation ofbe 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 1012.8 million short tons in 2009.2010.

    Executive Branch Action.    In 2007, the U.S. Supreme Court ruled inMassachusetts 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

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needed. In response, and as a reflection of current Administration priorities, 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. Other relevant rules, while not yet finalized, could lead to the direct regulation of greenhouse gas emissions from power plants. Inwelfare, following a September 2009 EPA proposed a rule relating to the regulation of greenhouse gases from light-duty vehicles. In October 2009, EPA proposed another rule conveying its interpretation of when a pollutant (such as a greenhouse gas like carbon dioxide) becomes "subject to regulation" under the Clean Air Act. Also in October 2009, EPA proposed significance thresholds for greenhouse gas emissions, to determine when new or modified stationary sources could trigger new source review and issued a 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. Until very recently,In April 2010, EPA has stated its intentionissued a rule that establishes when a pollutant (like carbon dioxide) becomes "subject to finalize these proposed rulesregulation" 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 Spring of 2010,PSD and has taken the position thatTitle V programs. Together, these rules when finalized wouldestablish 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 the process of regulating emissionsJuly 1, 2011 for larger sources of greenhouse gases, from both mobile and stationary sources. In late February of 2010, however, EPA indicated that new source reviewwhile a possible third step for major stationary sources ofsmaller greenhouse gas emissions would not be triggered before January 1, 2011.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 2010. That rulemaking is in response to a petition for review of EPA's refusal to adopt regulations governing power plant emissions of carbon dioxide and other greenhouse gases under the Clean Air Act. After the Supreme Court reached its decision inMassachusetts v. EPA, the U.S. Court of Appeals for the D.C. Circuit remanded the case back to EPA in September 2007 for further proceedings in light of that decision. Both of the2011. The final rules discussed above are subject to numerous petitions for review, and challenges to the remainingfuture rules may be brought if and when such rules are finalized. We cannot predict at this time whether thesehow further developments will ultimately result inmay affect the regulation of greenhouse gas emissions from our power plants, or the effects of any such regulation.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. InFor 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 2005, the Court granted the defendants' motions to dismiss, which the plaintiffs appealed in October 2005. In September 2009, the U.S. Court of Appeals for the Second Circuit ruled in favorvacated an earlier dismissal of the plaintiffs, vacating dismissal of theirplaintiffs' claims, and remanding the case back to the district court.Southern District. In November defendants sought rehearing inDecember 2010, the case, which also is subject to a potential appeal.

    In an October 2009 decision involving common law claims for both injunctive relief and property damage allegedly caused by greenhouse gas emissions, the U.S.Supreme Court of Appeals for the Fifth Circuit reversed the U.S. District Court for the Southern District of Mississippi's dismissal of private property claims against certain oil, coal, chemical and utility companies alleging damages from Hurricane Katrina. In reversing the case, the Fifth Circuit held that plaintiffs have standing to assert their nuisance, trespass and negligence claims. Contrary to the decision of the District Court, the Fifth Circuit concluded that these claims were not barred by the political question doctrine where, under separation of power principles, federal courts decline to rule on questions deemed more appropriate for action first by Congress or the Executive Branch. In March of 2010, however, the Fifth Circuit agreed to a rehearing of the case before the entire Court.

    In February 2008, the Native Village of Kivalina and the City of Kivalina filed suit in the U.S. District Court for the Northern District of California against several electric utilities, several oil companies and one coal company, alleging that their village in Alaska is being destroyed by erosion caused by global warming attributable to defendants' greenhouse gas emissions. The plaintiffs assert claims for public and private nuisance and seek damages, on a joint and several basis and in the range of $95 million to $400 million from defendants for lost property values and the costs of relocating the village. In September of 2009, the district court granted defendants' motions to dismiss the case,

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ruling the plaintiffs lacked standing to bring the case and that plaintiffs' claims were barred by the political question doctrine. Plaintiffs appealed the case to the U.S. Court of Appeals for the Ninth Circuit in November of 2009.

    In June 2008, a Fulton County, Georgia Superior Court Judge overturnedhear an air quality permit issued to Longleaf Energy Associates, LLC for the construction of a coal-fired power plant in Early County, Georgia. This permit had previously been upheld by the Office of State Administrative Hearings (OSAH) after an appeal by the Sierra Club and Friends of the Chattahoochee. The judgment set aside OSAH's decision, concluding that carbon dioxide emissions are regulated and thus require permitting under the Clean Air Act. On appeal, the decision was reversed by the Georgia Court of Appeals. The case was, for other reasons, remanded for further OSAH evidentiary proceedings unrelated to the carbon dioxide issue. Sierra Club and Friends of the Chattahoochee applied for discretionary appeal of the case, to the Georgia Supreme Court, which in September 2009, decided not to hear the appeal. Recently, Sierra Club and Friends of the Chattahoochee filed a motion for reconsideration with the Georgia Supreme Court. That motion was denied, ending the appeal. Ongoing litigation and administrative review actions are pending in other states, where, like the Georgia case, it is being argued that best available control technology is required for carbon dioxide emissions from new or modified sources under the Clean Air Act. We cannot predict at this time whether any of these actions will result in the regulation of greenhouse gas emissions from our power plants, or the effects of any such regulation.

    Other issues raised by global climate change are also being litigated in courts throughout the United States. For example, a current case in the United States District Court for the District of Columbia (Sierra Club v. USDA, et al.; No. 07-1860) is based on an argument that the consents or approvals issued by the Rural Utilities Service in its capacity as a lender for a coal-fired power plant constitute a major federal action triggering the review requirements of the National Environmental Policy Act (NEPA), which requires federal agencies to assess the environmental impacts of their major actions. Other litigation addresses the extent to which any reviewing federal agency must consider the impact of greenhouse gas emissions in the National Environmental Policy Act review process. In February 2010, the Council on Environmental Quality issued draft guidance confirming that federal agencies, when conducting their scoping reviews under NEPA, should consider whether an analysis of direct and indirect emissions of greenhouse gases from their proposed actions may provide meaningful information to decision-makers and the public. Federal agencies are instructed to consider not only whether evaluated actions may increase emissions of greenhouse gases, but also the relationship climate change effects may have on proposed and considered actions. Given the broad nature of these inquiries, we cannot currently predict how greenhouse gas emissions issues will arise in connection with our pending or future interaction with federal agencies, including the pursuit of necessary consents, approvals or permits, or whether litigation based on climate change issues will adversely affect our construction and development plans.

    International Developments.    International climate change negotiations under the United Nations Framework Convention on Climate Change continue. In the latest round of formal discussions in Copenhagen in December of 2009, nonbinding agreements were reached that included a pledge from participating countries to reduce their emissions of greenhouse gases. The outcome and impact of these international negotiations cannot be determined at this time.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

    AfterIn 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 release of over five million cubic yards of fly ash from a power plant ash storage facility in Tennessee in December 2008, EPA has been under increased pressure to regulate the handling and storagebeneficial use of coal combustion products at the federal level. Coal combustionbyproducts, a designation as hazardous waste disposed inmay 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 surface impoundments is currently a regulated solid waste only at the state levelgroundwater monitoring facilities, and in most cases is not considered a hazardous waste. As partadditional material management and financial assurance requirements. Depending upon which method of a 2000 regulatory determination,regulation EPA had been developing national solid waste management standards to address coal combustion wasteselects, if any, preliminary estimates by many utilities and is continuing to consider whether coal combustion waste may continue to be classified asindustry groups suggest that compliance costs are greater than originally anticipated

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non-hazardous under the Resource Conservationby EPA and Recovery Act. The new standards, expected in early 2010,could be significant; however, any compliance costs will likely include increased groundwater monitoring, more stringent siting requirements and closure of existing coal waste management facilities not meeting minimum standards. EPA has requested information on current ash impoundments at coal-fired power plants and is continuing to evaluate the safety of these structures. In January 2010, EPA also proposed to include the electric utility industry among those for which it plans to develop proposed regulations identifying appropriate financial responsibility requirements under the Comprehensive Environmental Response, Compensation, and Liability Act. Dependingdepend on the outcomefinal form of these rulemakings, we may incur substantial additional costs for the management, beneficial userules adopted, if any, and disposal of these wastes.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.

    We, As an owner, co-owner and/or operator of generating facilities, in which we have an interest, 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.

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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.

    Applications haveThe 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 an early site permit and 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 outcomestatus 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 2015.2014. 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, 2009,2010, we had $4.3approximately $4.8 billion of long-term debt outstanding. For 20102011 through 2017, we project that we will invest approximately $6.0$4 billion to $8.0 billion in newconstruct and acquire additional generation facilities and upgrades to upgrade our existing generation facilities. As a result, of this program, we project that we will have approximately $10.0$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 for 2009 and 2010 to achieve 1.12 and 1.14a greater margins for interest ratios, respectively; each aboveratio 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 these higherincreased 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 construction.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.

    Our existing facilities require ongoing capital expenditures in orderIn connection with our construction projects related to maintain efficientnew generating resources and reliable operations. Many of our facilities were constructed over 20upgrades to 30 years ago and, as a result, may require significant capital expenditures in order to maintain efficiency and reliability, and to comply with changing environmental requirements. In addition, due to projected growth in their service territories as well as the expiration or renegotiation of certain of their supplemental power supply agreements, our members have requested that we expand our existing generating facilities and build or acquire new generating facilities, which will requireresources, we have committed to significant capital expenditures and investment.

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;

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continued public and policymaker support;

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unforeseen engineering problems;

•

performance by engineering, construction or procurement contractors;

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potential contract disputes;

•

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

•

work stoppages;

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permits, approvals and other regulatory matters;

•

adverse weather conditions;

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unforeseen engineering problems;

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environmental and geological conditions;

•

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

•

unanticipated increases in the costs of materials and labor;

•

performance by engineering, constructionchanges in project design or procurement contractors;scope;

•

increases in our cost of debt financing; and

•

attentiondelays or increased costs to other projects.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. Althoughuncertain; however, our engineering, procurement and construction contract for the additional

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units at Plant Vogtle limits our exposure to increases in construction costs,costs. Further, we could be exposedrely on Georgia Power and Southern Nuclear to act as our agents for the development and construction of the additional riskunits at Plant Vogtle and do not exercise direct control over the development and construction process.

Table of cost uncertainty in connection with future projects.Contents

    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 and/or international negotiations, we may become subject to regulatory, legislative regulatory 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 continuecontinue. Although climate change legislation has not been adopted at the federal level, EPA continues to increase. EPA has issued an Advance Noticemove forward with the regulation of Proposed Rulemaking that suggests various alternatives for regulating greenhouse gasesgas 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 also made an "endangerment finding" fortaken 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 if carried through, wouldapply 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 series of events that could resultrevised New Source Performance Standard for steam generating units operated by electric utilities, and other industrial and commercial facilities in the regulation of carbon dioxide as an air pollutant.2011 which will be finalized by mid-2012. Many of our electric generating facilities are likely to bepotentially subject to these new or pending regulations.

    Unlike last year, when legislation was under consideration would have imposed new regulation under climate change laws and/or regulations which result from these activities within the next few years. In 2009, our generation resources emitted approximately 10 million short tons ofmore stringent emissions limitations for greenhouse gases, including carbon dioxide. In 2009, 41% of our generation, excluding pumped storage, came from our interestdioxide, on power plants, several proposals in the coal-fired Plants Scherer and Wansley, which112^th Congress would beostensibly limit the most impacted by anyauthority of EPA to continue regulation of greenhouse gas relatedgases. However, even if limiting legislation or regulation, while another 12% came from our gas-fired facilities (which wouldis passed, Congress may also be somewhat impacted but not to the same extent as the coal-fired facilities). The remaining generation (47%) came from our interest in the nuclear Plants Vogtle and Hatch and would not likely be impacted by any climate change legislation or regulation.

    Many of the climate change legislative proposals use a "cap-and-trade" policy structure, in which carbon dioxide and other greenhouse gas emissions from some portion of the economy would be subject to an overall cap, which would decrease (i.e., become more stringent) over time. For example, the Waxman-Markey bill, which was passed by the House of Representatives in June 2009, proposes to enact a cap-and-trade regime in orderdecide to regulate carbon dioxide and other greenhouse gas emissions. Senate proposals are similar. Generally, the proposals establish mechanisms for emissions sources, such as power plants, to obtain "allowances" or permits to emit carbon dioxide and otherof greenhouse gases, during the courseeither directly or through some type of the year, somewhat similar to the emission allowance trading program for sulfur dioxide established by the Clean Air Act Amendments of 1990. However, unlike the program for sulfur dioxide, we and other utilities may need to purchase all or many of the necessary allowances in an auction format, rather than being issued allowances at no additional cost.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. Nonbinding agreements to reducecontinue, 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 gases were made pursuantgas-related legislation or regulation, while another 10% came from our gas-fired facilities (which would also be somewhat impacted but not to the latest round of formal discussions late last year,same extent as the coal-fired facilities). The remaining generation (44%) came from our interest in the nuclear Plants Vogtle and subsequent developments could produce binding obligations for emissions reductions.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 would dependdepends upon the specific requirements created and cannot be determined at this time. For example, the impact of currently proposed legislationregulations relating to greenhouse gas emissions would depend on a variety of factors, including the specific greenhouse gas emission limits or renewable energy requirements, the timing of implementation of these limits or requirements, the level of emissions allowances allocated and amounts that must be purchased, the purchase price of emissions allowances, the development of suitable technologies for renewable energy and the reduction and/or sequestration of emissions, the degree to which offsets may be used for compliance, provisions for cost containment, if any, and the impact on coal and natural gas prices.such emissions.

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Our access to, and cost of, capital could be adversely affected by various factors, including current market conditions, limitations on the availability of Rural Utilities Servicefederally-guaranteed loans and our credit ratings, and significantratings. 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. Historically, weUnlike 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, (aa branch of the U.S. Department of Agriculture)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. The President's budget for fiscal year 2011 proposes to reduce funding by almost 40% from 2010 levels and, in support of the President's commitment to reduce inefficient fossil-fuel subsidies, prohibits loans for new or existing fossil-fueled generation. The budget limits the use of electric loan funds to renewable energy, transmission, distribution and carbon-capture projects on generation facilities. 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. 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."

    We have applied for partial funding from the Federal Financing Bank, coupledIn connection with a guarantee from the Department of Energy, to fund our share of the cost of constructing two additional nuclear units at Plant Vogtle. On February 16,Vogtle, in May 2010 the Department of Energy presented us withwe signed a conditional term sheet that setsets forth the general terms of a loan from the Federal Financing Bank and a related loan and offered a guarantee from the Department of Energy that would targetfund approximately 70% of eligible project costs, not to exceed $3.057 billion. We have until May 17, 2010 to accept the terms of the conditional term sheet. We will workare 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 isare 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 new generation construction thatexpansion we have planned over the next decadeseven 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. OurIf one or more rating agencies downgrade us, our borrowing costs could increase and our potential pool of investors, funding sources and liquidity could decreasedecrease. In addition, if our credit ratings are lowered particularly if our ratings are lowered below investment grade.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 currentrecent uncertainty in the credit and capital markets;

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•

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;

    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. For example, in 2008, the credit downgrades of AMBAC Indemnity Corporation and American International Group, Inc. triggered certain requirements under certain of our agreements which have now been satisfied. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition –Off-Balance Sheet Arrangements-Rocky Mountain Lease Arrangements."

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 currentrecent economic conditions, sales by our members may not be sufficient to cover current 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.

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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, 2010,2011, we had a 103-day37-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, 2010,2011, our coal stockpile at Plant Scherer contained a 62-day39-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. OurThe leases expire in 2013, with options to renew for a total of 8.5 years. We also haveinclude fair market value purchase options at specified dates, including 2013 and the end of lease renewal terms. We treat these transactions as capital leases for financial reporting purposes. (Seedates. 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

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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 over a 15-year term. Delivery commencedthrough May 15, 2000.2015.

    During the term of the agreement, we have the right and obligation to purchase all of the capacity and

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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 treataccount 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, 2009, have2010, 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.

Future Capital RequirementsExpansion of Generation Capacity

    Over the last several years, we have focused our efforts on developing a menu ofand acquiring various generation optionsresources that offersoffer our members moregreater ownership and control over their generation resources (through us)needs, through us, in order to help mitigate their reliance on third-party contracts. In furtherance ofTo advance these efforts, we have taken the following actions:

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We and the other co-owners of Plant Vogtle agreed to developare developing two additional nuclear units at the Plant Vogtle site with eachan aggregate generating capacity of 2,200 megawatts. Each co-owner is maintaining the same percentage ownership in the two new units as they have in the existing units. Ourunits 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 30% interest in the two new units, including the 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.

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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.

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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.

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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.

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We are pursuing development of one 100 megawatt biomass-fueled generating plant. The plant is planned for commercial operation in 2014. We have acquired a site for this facilityalso deferred the 100-megawatt Warren County biomass plant; however, we continue to monitor regulatory and are conducting preliminary engineering work and environmental analyses. Our estimated costlegislative developments related to construct this facility is $477 million, including allowance for funds used during construction.

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We are pursuing the development of one natural gas-fired 605 megawatt combined cycle facility with a target completion date of 2015. We are in the process of evaluating sites and plan to begin our preliminary engineering work and environmental analyses later this year. Our estimated cost to construct this facility is approximately $750 million, including allowance for funds used during construction.biomass electricity generation.

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We and our members are currently evaluating additional specific gas-fired combustion turbine plants and combined cycle plants. Decisions regarding the acquisition or construction of these plants are expected to be made over athe next two to three year period beginning as early as 2010.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 $800$934 million through 2012. These expenditures include

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2013, which includes normal additions and replacements to plant in-service andexisting plants as well as required projects to maintain and achieve compliance with current and anticipated environmental requirements. Importantly, this forecast does not include additional capital expenditures or increased operational expenses for Plants Wansley and Scherer due to climate change legislation andor coal combustion by-products regulation which is likely to be enacted or adopted in the future.

20092010 Financial Results

    Despite generalcontinued 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 20092010 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 $26.4$33.7 million in 2009,2010, 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 improveincrease our margin coverage in light of current financial market conditions and athe period of increased capital requirements, as noted above. Consequently, for the first time since our margins for interest ratio rate covenant was institutedbeginning in 1997,2009, we arebegan targeting higher margins than what would otherwise be necessary to meet the minimum required margins for interest ratio of 1.10 required under the first mortgage indenture. For 2009 and 2010, we collected revenues sufficient to achieve a margins for interest ratioratios of 1.12 and 1.14, respectively, effectively increasing our annual margin targetmargins 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 2010,2011, we are again targeting a margins for interest ratio of 1.14. As our generation constructionexpansion 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 financial attributes that contributescontributing to our competitivesolid financial standing. In this regard, we maintained a strong liquidity position despite the disruptionDespite recent disruptions in the global financial markets, in 2008we maintained strong liquidity and, strengthened our liquidity position throughout 2009the past two years as financial market conditions became more favorable.favorable, we strengthened our liquidity position. At December 31, 2009,2010, we had $1.3$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 commercial paper program.$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 2009, in addition to usingmaintaining 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 liquidityconstruction and acquisition activity. RUS has approved loans to finance new generation projects, we issued $274 million of commercial paper to finance two acquisitions and refinance debt we assumed in conjunction with one of these acquisitions. In May we acquiredprovide long-term funding for the Hawk Road Energy Facility (a 500 megawatt peaking facility in Heard County, Georgia) and in OctoberHartwell facilities, and we acquired the Hartwell Energy Facility (a 300 megawatt oil and gas-fired peaking facility in Hart County, Georgia). Ashave issued $850 million of taxable first mortgage bonds to finance a result, we believe thatportion of our liquidity management program not only provides uscosts associated with the abilityadditional units at Plant Vogtle. We have also executed a conditional commitment letter with the Department of Energy to meet our financial obligations, but also provides us withsecure a significant competitive advantage that will contributelong-term loan guarantee for up to our ability to meet70%, or $3.057 billion, of eligible project costs for the future energy needs of our members in a cost-effective manner.additional units at Plant Vogtle.

Outlook for 20102011

    We will 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 be addressed,address, including:

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

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

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

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Fuel cost volatility, including related transportation costs.

    We believe that we continue to be well-positionedwell positioned to provide reliable, cost-effective energy to our members and their consumers. As we manage our way through these risks, we intend to keep doing what we have done so successfully for the last 3637 years, including, among other things:

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

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Working with our members to evaluate new resources, including, renewables where feasible, renewable resources, to

requirements; and

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Maintaining a strong liquidity position to fulfill our 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 $562$596 million in patronage capital and membership fees as of December 31, 2009.2010. 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 and 12.6% at December 31, 2008.2009.

    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 termlong-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 ourthe 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.

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    In 2008 and 2007, 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 a budgetbudgets 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 20102011 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 further increase, or decrease,change the targeted margins for interest ratio in the future.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'sBoard (FASB) authoritative guidance issued regarding Accounting for the Effects of Certain Types of Regulation.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, 2009,2010, our regulatory assets and liabilities totaled $358$311 million and $109$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 Accountingaccounting for the Effects of Certain Types of Regulation,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 September 2009, we adopted the FASB Codification and the Hierarchy of Generally Accepted Accounting Principles (Codification). The Codification creates a two-level GAAP hierarchy – authoritative and non-authoritative – and establishes the Codification as the sole source of authoritative GAAP for non-governmental entities, except for rules and interpretive releases issued by the SEC. The Codification had no impact on our results of operations, cash flows or financial condition.

    Effective January 1, 2009, we adopted FASB authoritative guidance issued regarding Disclosures about Derivative Instruments and Hedging Activities. The standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures that reflect the effect of these activities on an entity's financial position, financial performance, and cash flows. For a discussion of the effect of derivative instruments and hedging activities on our results of operations, cash flows and financial condition, see Note 2 in Notes to Consolidated Financial Statements.

    In November 2007,2010, the FASB issued a one-year deferral for the implementation of Fair Value Measurements and Disclosures – Improving Disclosures about Fair Value Measurements. The new guidance provides for non-financial assets and non-financial liabilities that are recognized or disclosed atimproved disclosure requirements about fair value measurements and requires a reporting entity to disclose separately the amounts of significant transfers in the financial statements on a nonrecurring basis. The

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deferral was applicable for asset retirement obligations measured atLevel 1 and Level 2 fair value upon initial recognition under Accounting for Asset Retirement Obligations, or upon a remeasurement event. We adopted Fair Value Measurements for non-financial assetsmeasurements and non-financial liabilities effective January 1, 2009 with no material effect on our results of operations, cash flows or financial condition.

    Effective June 30, 2009, we adopted FASB standard Determining Fair Value Whendescribe the Volume and Level of Activityreasons for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly.transfers. The standard emphasizesguidance also clarifies that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique and inputs used, the objective for the fair value measurement is unchanged from what it would be if markets were operating at normal activity levels or transactions were orderly; that is, to determinedisclosures are required for each asset class. In the current exit price. The standard sets forth additional factors that should be considered to determine whether there has been a significant decrease in the volume and level of activity when compared with normal market activity. The reporting entity should evaluate the significance and relevance of the factors to determine whether, based on the weight of evidence, there has been a significant decrease in activity and volume. The standard indicates that if an entity determines that either the volume or level of activityreconciliation for an asset or liability has significantly decreased (from normal conditions for that asset or liability) or price quotations or observable inputs are not associated with orderly transactions, increased analysis and management judgment will be required to estimate fair value. The standard further notes that a fair value measurement should include a risk adjustment to reflectmeasurements using significant unobservable inputs (Level 3), the amount market participants would demand because of the risk (uncertainty) in the cash flows.

    This standard also requires a reporting entity to make additional disclosures in interimpresent separately information about purchases, sales, issuances, and annual periods. Revisions resulting fromsettlements (that is, on a change in valuation techniques or their application are accountedgross 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 as a change in accounting estimate.us until the quarter ending March 31, 2011. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.

    Effective June 30, 2009, we adopted FASB authoritative guidance Interim Disclosures about Fair Value of Financial Instruments. The standard requires disclosures about the fair value of financial instruments in interim and annual financial statements. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.

    Effective June 30, 2009, we adopted FASB standard Subsequent Events. The standard establishes general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. It requires management to evaluate events or transactions that may occur for potential recognition of disclosure in the financial statements, the circumstances under which events or transactions occurring after the balance sheet date should be recognized and events or transactions that should be disclosed that occur after the balance sheet date. The adoption of the standard did not have a material effect on our results of operations, cash flows or financial condition.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 Consolidationconsolidation of Variable Interest Entitiesvariable 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.

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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.