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

FORM 10-K

FOR ANNUAL AND TRANSITION REPORTS
PURSUANT TO SECTIONS 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

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

       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 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. [X]

       Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2). 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. None

       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

OGLETHORPE POWER CORPORATION

2004 FORM 10-K ANNUAL REPORT

Table of Contents

i

SELECTED DEFINITIONS

        The following terms used in this report have the meanings indicated below:

ii

PART I

ITEM 1. BUSINESS

OGLETHORPE POWER CORPORATION

General

    Oglethorpe Power Corporation (An Electric Membership Corporation) ("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta. Oglethorpe is owned by 38 retail electric distribution cooperative members (the "Members"). Oglethorpe's principal business is providing wholesale electric power to the Members. As with cooperatives generally, Oglethorpe operates on a not-for-profit basis. Oglethorpe is the largest electric cooperative in the United States in terms of operating revenues, assets, kilowatt-hour ("kWh") sales and, through the Members, consumers served. Oglethorpe has 168 employees.

    The Members are local consumer-owned distribution cooperatives providing retail electric service on a not-for-profit basis. In general, the customer base of the Members consists of residential, commercial and industrial consumers within specific geographic areas. The Members serve approximately 1.5 million electric consumers (meters) representing approximately 3.7 million people. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES.")

    From 1974 to 2004, Oglethorpe served 39 Members. However, effective January 1, 2005, Flint EMC withdrew from membership in Oglethorpe. (See "Competition" below.)

    Oglethorpe's mailing address is 2100 East Exchange Place, Tucker, Georgia 30084-5336, and its telephone number is (770) 270-7600.

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. Any such 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

    Oglethorpe provides wholesale electric service to the 38 Members for a substantial portion of their requirements from a combination of its generation assets and power purchased from power marketers and other suppliers. Oglethorpe provides this service pursuant to long-term, take-or-pay Amended and Restated Wholesale Power Contracts, dated January 1, 2003 (the "Wholesale Power Contracts"). The Wholesale Power Contracts obligate the Members jointly and severally to pay rates sufficient to recover all the costs of owning and operating Oglethorpe's power supply business. Taking into consideration the approval requirements for future resources in the Wholesale Power Contracts, Oglethorpe anticipates that the Members will satisfy all of their requirements above their Oglethorpe purchase obligations with purchases from other suppliers. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.")

    Oglethorpe has undivided interests in 24 generating units. These units provide Oglethorpe with a total of 4,744 megawatts ("MW") of nameplate capacity, consisting of 1,501 MW of coal-fired capacity, 1,185 MW of nuclear-fueled capacity, 632 MW of pumped storage hydroelectric capacity, 1,411 MW of gas-fired capacity (206 MW of which is capable of running on

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oil) and 15 MW of oil-fired combustion turbine capacity.

    Oglethorpe purchases a total of approximately 550 MW of power pursuant to long-term power purchase agreements. (See "OGLETHORPE'S POWER SUPPLY RESOURCES" and "PROPERTIES – Generating Facilities.")

    In 2004, two of Oglethorpe's Members, Jackson EMC and Cobb EMC, accounted for 12.0% and 10.1% of Oglethorpe's total revenues, respectively. None of the other Members accounted for as much as 10% of Oglethorpe's total revenues in 2004.

Wholesale Power Contracts

    Oglethorpe has a substantially similar Wholesale Power Contract with each Member extending through December 31, 2025. For information regarding a potential extension of these contracts, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – EXECUTIVE OVERVIEW." Under the Wholesale Power Contract, each Member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs (referred to as a "percentage capacity responsibility") of each of Oglethorpe's generation and purchased power resources. 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. Oglethorpe is obligated to use its reasonable best efforts to operate, maintain and manage its resources in accordance with prudent utility practices.

    Percentage capacity responsibilities have been assigned to all of Oglethorpe's generation and purchased power resources. Percentage capacity responsibilities for any future resource will be assigned 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 (as described below) future resources, whether or not such Member has elected to participate in such 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 such default.

    To acquire future resources, Oglethorpe is required to obtain the approval of 75% of Oglethorpe's Directors, 75% of the Members and Members representing 75% of the patronage capital of Oglethorpe. Certain resource modifications can be made by Oglethorpe if approved by more than 50% of Directors and 50% of the Members.

    Under the Wholesale Power Contracts, Oglethorpe is not obligated to provide all of the Members' capacity and energy requirements. Individual Members must satisfy all of their requirements above their Oglethorpe purchase obligations from other suppliers, unless Oglethorpe and the Members agree that Oglethorpe will supply additional capacity and associated energy, subject to the approval requirements described above. (See "THE 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 Oglethorpe 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

    In 2003, Oglethorpe and its Members entered into a New Business Model Member Agreement. The agreement requires Member approval for Oglethorpe to undertake certain activities. It does not limit Oglethorpe's ability to own, manage, control and operate its resources or perform its functions under the Wholesale Power Contracts.

    Oglethorpe may not provide services unrelated to its resources or its functions under the Wholesale Power Contracts if such services would require it to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of Oglethorpe's Board of Directors, 75% of the Members, and Members representing 75% of the patronage capital of Oglethorpe. Oglethorpe may provide any other such service to a Member so long as (1) doing so would not

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create a conflict of interest with respect to other Members, (2) such service is being provided to all Members or (3) such service has received the three-part 75% approval described above.

Electric Rates

    Each Member is required to pay Oglethorpe for capacity and energy furnished under its Wholesale Power Contract in accordance with rates established by Oglethorpe. Oglethorpe reviews its rates at such intervals as it deems appropriate but is required to do so at least once every year. Oglethorpe is required to revise its rates as necessary so that the revenues derived from its rates, together with its revenues from all other sources, will be sufficient to pay all costs of its system, to provide for reasonable reserves and to meet all financial requirements.

    Oglethorpe's principal financial requirements are contained in the Indenture, dated as of March 1, 1997, from Oglethorpe to SunTrust Bank, as trustee (as supplemented, the "Mortgage Indenture"). Under the Mortgage Indenture, Oglethorpe is required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with other revenues of Oglethorpe, to yield a Margins for Interest Ratio for each fiscal year equal to at least 1.10. "Margins for Interest Ratio" is the ratio of "Margins for Interest" to total "Interest Charges" for a given period. Margins for Interest is the sum of:

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net margins of Oglethorpe (which includes revenues of Oglethorpe 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 Oglethorpe determines to recover such charges in rates, and (ii) refunds of revenues collected or accrued subject to refund), plus

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interest charges, whether capitalized or expensed, on all indebtedness secured under the Mortgage Indenture or by a lien equal or prior to the lien of the Mortgage Indenture, including amortization of debt discount or premium on issuance, but excluding interest charges on indebtedness assumed by Georgia Transmission Corporation ("Interest Charges"), plus

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

    Margins for Interest takes into account any item of net margin, loss, gain or expenditure of any affiliate or subsidiary of Oglethorpe only if Oglethorpe has received such net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if Oglethorpe has made a payment with respect to such losses or expenditures.

    The formulary rate established by Oglethorpe 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 Oglethorpe's revenue requirements. The rate schedule also implements the responsibility for fixed costs assigned to each Member (that is, the Member's percentage capacity responsibility). The monthly charges for capacity and other non-energy charges are based on Oglethorpe's annual budget. Such capacity and other non-energy charges may be adjusted by the 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 Oglethorpe achieves the minimum 1.10 Margins for Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum 1.10 Margins for Interest Ratio are accrued as of December 31 of the applicable year and collected from the 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 recorded by Oglethorpe, plus amounts necessary to achieve at least the minimum 1.10 Margins for Interest Ratio.

    Under the Mortgage Indenture and related loan contract with the Rural Utilities Service ("RUS"), adjustments to Oglethorpe's rates to reflect changes in Oglethorpe's budgets are generally not subject to RUS approval. Changes to the rate schedule under the Wholesale Power Contracts are generally subject to RUS approval. Oglethorpe's rates are not subject to the approval of any other federal or state agency or

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authority, including the Georgia Public Service Commission (the "GPSC").

Relationship with Smarr EMC

    Smarr EMC is a Georgia electric membership corporation owned by 36 of Oglethorpe's 38 Members. Smarr EMC owns two combustion turbine facilities with aggregate capacity of 709 MW. Oglethorpe provides, operations, financial and management services for Smarr EMC. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.")

Relationship with GTC

    Oglethorpe, the 38 Members and Flint EMC are members of Georgia Transmission Corporation (An Electric Membership Corporation) ("GTC"), which was formed in 1997 to own and operate the transmission business previously owned by Oglethorpe. GTC provides transmission services to its members for delivery of the members' power purchases from Oglethorpe and other power suppliers. GTC also provides transmission services to third parties. Oglethorpe has entered into an agreement with GTC to provide transmission services for third party transactions and for service to Oglethorpe's own facilities.

    In 1997, GTC assumed certain indebtedness associated with pollution control bonds ("PCBs") originally issued on behalf of Oglethorpe. If GTC fails to satisfy its obligations under this debt, Oglethorpe would then remain liable for any unsatisfied amounts. (See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Off-Balance Sheet Arrangements.")

    GTC has rights in the Integrated Transmission System, which consists of transmission facilities owned by GTC, Georgia Power Company ("GPC"), the Municipal Electric Authority of Georgia ("MEAG") and the City of Dalton ("Dalton"). 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 GSOC

    Oglethorpe, GTC and the 38 Members are members of Georgia System Operations Corporation ("GSOC"), which was formed in 1997 to own and operate the system operations business previously owned by Oglethorpe. GSOC operates the system control center and currently provides system operations services and administrative support services to Oglethorpe and to GTC. Oglethorpe has contracted with GSOC to schedule and dispatch Oglethorpe's resources. Oglethorpe also purchases from GSOC services that GSOC purchases from GPC under the Control Area Compact, which Oglethorpe co-signed with GSOC. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Members' Relationship with GTC and GSOC.") GSOC provides support services to Oglethorpe in the areas of accounting, auditing, communications, human resources, facility management, telecommunications and information technology at cost-based rates.

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

    GSOC, Oglethorpe and the Members are evaluating how GSOC implements the procedures for Members to schedule energy from Oglethorpe's resources. This evaluation could result in changes in the Operation Services Agreement between Oglethorpe and GSOC, as well as changes in the contractual relationships among GSOC and the Members. It would not, however, change the terms of Oglethorpe's Wholesale Power Contracts with the Members.

    Oglethorpe has a small amount of loans to GSOC and also has secondary liability on a small amount of GSOC indebtedness and GSOC contractual obligations.

Relationship with RUS

    Historically, federal loan programs administered by RUS have provided the principal source of financing for electric cooperatives. Loans guaranteed by RUS and made by the Federal Financing Bank ("FFB") have been a major source of funding for Oglethorpe. However, the availability and magnitude of RUS-guaranteed loan funds is subject to annual federal

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budget appropriations and thus cannot be assured. Currently, RUS-guaranteed loan funds are subject to increased uncertainty because of recent budgetary pressures faced by Congress. In addition, proposed and evolving policies within the Bush Administration and RUS may limit loan funds where the proceeds are slated for use in "urban" rather than "rural" areas, in certain circumstances where a generation and transmission ("G&T") cooperative's members are no longer RUS borrowers. As currently discussed, this particular new policy has the potential to affect Oglethorpe in a way that limits its ability to access RUS financing for new generation facilities more than other RUS borrowers because of its unique circumstances. Some of Oglethorpe's faster-growing suburban area Members are no longer RUS borrowers. Conversely, because Oglethorpe's Wholesale Power Contracts allow the Members to purchase power from other suppliers, Oglethorpe may also be less affected than other G&T borrowers. Because of these factors, Oglethorpe cannot predict the amount or cost of RUS-guaranteed loans that may be available to Oglethorpe in the future.

    Oglethorpe has a loan contract with RUS in connection with the Mortgage Indenture. Under the loan contract, RUS 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,

•

changes to the Wholesale Power Contracts and the rate schedule contained therein,

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changes to plant ownership and operating agreements, and

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in limited circumstances, issuance of additional secured debt.

    The extent of RUS's approval rights under the loan contract with Oglethorpe is substantially less than the supervision and control RUS has traditionally exercised over borrowers under its standard loan and security documentation. In addition, the Mortgage Indenture improves Oglethorpe's ability to borrow funds in the public capital markets relative to RUS's standard mortgage. The Mortgage Indenture constitutes a lien on substantially all of the owned tangible and certain intangible property of Oglethorpe.

Relationship with GPC

    Oglethorpe's relationship with GPC is a significant factor in several aspects of Oglethorpe's business. All of Oglethorpe's co-owned generating facilities, except Rocky Mountain, are operated by GPC on behalf of itself as a co-owner and as agent for the other co-owners. GPC is one of Oglethorpe's suppliers of purchased power, and also supplies services to Oglethorpe and GSOC to support the scheduling and dispatch of Oglethorpe's resources, including off-system transactions. GPC and the 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 (the "Territorial Act"). For further information regarding the agreements with GPC and Oglethorpe's and the Members' relationships with GPC, see "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Service Area and Competition" and "OGLETHORPE'S POWER SUPPLY RESOURCES – Power Purchase and Sale Arrangements – Power Purchases." Also see "PROPERTIES – Fuel Supply," "– Co-Owners of Plants – Georgia Power Company" and "– The Plant Agreements."

Competition

    Under current Georgia law, the Members generally have the exclusive right to provide retail electric service in their respective territories. Since 1973, however, the 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. The Members are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. While the competition for 900-kilowatt loads represents only limited competition in Georgia, this competition has given the Members the opportunity to develop resources and strategies to prepare for an increasingly 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 Territorial Act or

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otherwise affect the exclusive right of the Members to supply power to their current service territories. The GPSC does not have the authority under Georgia law to order retail competition or amend the Territorial Act.

    Oglethorpe cannot predict at this time the outcome of the various developments that may lead to increased competition in the electric utility industry or the effect of such developments on Oglethorpe or the Members. Nonetheless, Oglethorpe has taken several steps to prepare for and adapt to the fundamental changes that have occurred or appear likely to occur in the electric utility industry and to reduce stranded costs. In 1997, Oglethorpe divided itself into separate generation, transmission and system operations companies in order to better serve its Members in a deregulated and competitive environment. Oglethorpe also has pursued an interest cost reduction program, which has included refinancings and prepayments of various debt issues, that has provided significant cost savings.

    Oglethorpe and/or the Members continue to consider a wide array of other potential actions to meet future power supply needs, to reduce costs, to reduce increasing risks of the competitive generation business and to respond to increasing competition. Alternatives that could be considered include:

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power marketing arrangements or other alliance arrangements;

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whether potential load fluctuation risks in a competitive retail environment can be shifted to other wholesale suppliers;

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whether power supply requirements will continue to be met by the current mix of ownership and purchase arrangements;

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potential participation in future power supply resources, and whether they will be owned by Oglethorpe or by other entities;

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

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the effects of nuclear license extensions;

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ways to extend the maturity of existing indebtedness in connection with extension(s) of plant operating licenses;

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the potential to prepay debt;

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the effects of 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.

    Oglethorpe will continue to consider industry trends and developments, but cannot predict at this time the results of these matters or any action Oglethorpe or the Members might take based thereon. Such consideration necessarily would take account of and are subject to legal, regulatory and contractual (including financing and plant co-ownership arrangements) considerations.

    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 GPSC to authorize Member affiliates to market natural gas. The GPSC is required to condition such 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. Oglethorpe has 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 Oglethorpe, and must be approved by Oglethorpe's Board of Directors. Assignments without withdrawal are governed by the Wholesale Power Contract and must be approved by both Oglethorpe's Board and RUS.

    From time to time, individual Members may be approached by parties indicating an interest in purchasing their systems. The Wholesale Power Contracts provide that a Member may not dissolve,

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liquidate or otherwise wind up its affairs without Oglethorpe's approval. A Member generally must obtain approval from Oglethorpe 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. The Member may enter such a transaction without Oglethorpe's approval if specified conditions are satisfied, including, but not limited to, an agreement by the transferee, satisfactory to Oglethorpe, 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.

    Effective January 1, 2005, one of Oglethorpe's members, Flint EMC, withdrew from Oglethorpe and assigned, with Oglethorpe's consent, its Wholesale Power Contract to Cobb EMC. A portion of the power supply resources covered by the Flint EMC Wholesale Power Contract were allocated to six other Members. Cobb EMC has also acquired Pataula EMC's distribution system and provided Oglethorpe a guarantee of Pataula EMC's payment obligations under its Wholesale Power Contract. Other Members could be considering similar arrangements.

Seasonal Variations

    The demand for energy by the Members is influenced by seasonal weather conditions. Historically, Oglethorpe's peak sales have occurred during the months of June through August. Energy revenues track energy costs as they are incurred and also fluctuate month to month. Capacity revenues reflect the recovery of Oglethorpe's 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.

OGLETHORPE'S POWER SUPPLY RESOURCES

General

    Oglethorpe supplies capacity and energy to the Members for a substantial portion of their requirements from a combination of its generating assets and power purchased from power marketers and other suppliers. Oglethorpe also has arrangements with power marketers to supply power and to reduce the cost of capacity and energy delivered to the Members.

Generating Plants

    Oglethorpe's 24 generating units consist of 30% undivided interests in the Edwin I. Hatch Plant ("Plant Hatch"), the Alvin W. Vogtle Plant ("Plant Vogtle") and the Hal B. Wansley Plant ("Plant Wansley"), a 60% undivided interest in the Plant Robert W. Scherer ("Plant Scherer") Unit No. 1 ("Scherer Unit No. 1"), and the Robert W. Scherer Unit No. 2 ("Scherer Unit No. 2"), a 74.61% undivided interest in the Rocky Mountain Pumped Storage Hydroelectric Facility ("Rocky Mountain"), a 100% interest in the Talbot Energy Facility ("Talbot"), a 100% interest in the Chattahoochee Energy Facility ("Chattahoochee") and a 100% interest in the Doyle I, LLC Generating Plant ("Doyle"), through a power purchase agreement that Oglethorpe treats as a capital lease, all totaling 4,744 MW of nameplate capacity.

    MEAG, Dalton and GPC also have interests in Plants Hatch, Vogtle and Wansley and Scherer Units No. 1 and No. 2. GPC serves as operating agent for these units. GPC also has an interest in Rocky Mountain, which is operated by Oglethorpe.

    See "PROPERTIES" for a description of Oglethorpe's generating facilities, fuel supply and the co-ownership arrangements.

Power Purchase and Sale Arrangements

Power Purchases

    Oglethorpe has an agreement with GPC to purchase capacity and associated energy on a take-or-pay basis. Under this agreement, Oglethorpe is purchasing and will continue to purchase 250 MW until March 31, 2006.

    Oglethorpe has a contract through 2019 to purchase approximately 300 MW of capacity from Hartwell Energy Limited Partnership, a joint venture between

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Centennial Energy Resources, LLC, a subsidiary of MDU Resources Inc., and American National Power, Inc., a subsidiary of National Power, PLC. This capacity is provided by two 150 MW gas-fired combustion turbine generating units on a site near Hartwell, Georgia. Oglethorpe has the right to dispatch the units.

    See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Contractual Obligations" for a discussion of Oglethorpe's commitments under these power purchase agreements and "Note 4 to Notes to Financial Statements" regarding a power purchase agreement with Doyle I, LLC that Oglethorpe treats as a capital lease. Also see "PROPERTIES – The Plant Agreements – Doyle."

    In addition, Oglethorpe also purchases small amounts of capacity and energy from "qualifying facilities" under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Under a waiver order from the Federal Energy Regulatory Commission ("FERC"), Oglethorpe historically made all purchases the Members would have otherwise been required to make under PURPA and Oglethorpe was relieved of its obligation to sell certain services to "qualifying facilities" so long as the Members make those sales. Purchases by Oglethorpe from such qualifying facilities provided less than 0.1% of Oglethorpe's energy requirements for the Members in 2004. Under their Wholesale Power Contracts, the Members may make such purchases instead of Oglethorpe.

Long-Term Power Sales

    Oglethorpe has an agreement to sell 100 MW of base capacity to Alabama Electric Cooperative, Inc. through December 31, 2005.

Other Power System Arrangements

    Oglethorpe has interchange, transmission and/or short-term capacity and energy purchase or sale agreements with approximately 70 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. Oglethorpe is currently actively trading with only about half of these counterparties due to Oglethorpe's risk management policies with respect to netting provisions and credit ratings. The development of and access to the Integrated Transmission System and the interconnections with other utilities, through transmission contracts with GTC and others, are key elements in Oglethorpe's and the Members' ability to make off-system sales and purchases.

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THE MEMBERS AND THEIR POWER SUPPLY RESOURCES

Member Demand and Energy Requirements

    The Members are listed below and include 38 of the 42 electric distribution cooperatives in the State of Georgia.

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

    The Members serve approximately 1.5 million electric consumers (meters) representing approximately 3.7 million people. The Members serve a region covering approximately 37,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 143 of the State's 159 counties. Sales by the Members in 2004 amounted to approximately 30 million megawatt hours ("MWh"), with approximately 66% to residential consumers, 32% to commercial and industrial consumers and 2% to other consumers. The Members are the principal suppliers for the power needs of rural Georgia. While the Members do not serve any major cities, portions of their service territories are in close proximity to urban areas and are experiencing substantial growth due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. The 38 Members have experienced average annual compound growth rates from 2002 through 2004 of 3% in number of consumers, 3% in MWh sales and 4% in electric revenues.

    The following table shows the aggregate peak demand and energy requirements of the Members for the years 2002 through 2004, and also shows the amounts of energy requirements supplied by Oglethorpe. From 2002 through 2004, demand and energy requirements of the Members increased at an average annual compound growth rate of 3% and 4%, respectively. These amounts include the requirements of Flint EMC, who was a member of Oglethorpe until December 31, 2004.

⁽¹⁾

System peak hour demand of the Members measured at the Members' delivery points (net of system losses), adjusted to include requirements served by Oglethorpe and Member resources behind the delivery points.

⁽²⁾

Retail requirements served by Oglethorpe and Member resources, adjusted to include requirements served by resources behind the delivery points. (See "Member Power Supply Resources" below.)

⁽³⁾

Includes energy supplied to Members for resale at wholesale.

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Service Area and Competition

    The Territorial Act regulates the service rights of all retail electric suppliers in the State of Georgia. Pursuant to the Territorial Act, the GPSC assigned substantially all areas in the State to specified retail suppliers. With limited exceptions, the Members have the exclusive right to provide retail electric service in their respective territories, which are predominately outside of the municipal limits existing at the time the Territorial Act was enacted in 1973. The principal exception to this rule of exclusivity is that electric suppliers may compete for most new retail loads of 900 kilowatts or greater. The GPSC may reassign territory only if it determines that an electric supplier has breached the tenets of public convenience and necessity. The GPSC may transfer service for specific premises only if: (i) the GPSC determines, after joint application of electric suppliers and proper notice and hearing, that the public convenience and necessity require a transfer of service from one electric supplier to another; or (ii) the GPSC finds, after proper notice and hearing, that an electric supplier's service to a premise is not adequate or dependable or that its rates, charges, service rules and regulations unreasonably discriminate in favor of or against the consumer utilizing such premise and the electric utility is unwilling or unable to comply with an order from GPSC regarding such service.

    Since 1973, the Territorial Act has allowed limited competition among electric utilities in Georgia by allowing the owner of any new facility located outside of municipal limits and having a connected load upon initial full operation of 900 kilowatts or greater to receive electric service from the retail supplier of its choice. The Members, with Oglethorpe's support, are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. The number of commercial and industrial loads served by the Members continues to increase annually. While the competition for 900-kilowatt loads represents only limited competition in Georgia, this competition has given Oglethorpe and the Members the opportunity to develop resources and strategies to operate in an increasingly competitive market.

    For further information regarding Member competitive activities, see "OGLETHORPE POWER CORPORATION – Competition."

Cooperative Structure

    The Members are cooperatives that operate their systems on a not-for-profit basis. Accumulated margins derived after payment of operating expenses and provision for depreciation constitute patronage capital of the consumers of the Members. Refunds of accumulated patronage capital to the individual consumers may be made from time to time subject to limitations contained in mortgages between the Members and RUS or loan documents with other lenders. The RUS mortgages generally prohibit such distributions unless (1) after any such distribution, the Member's total equity will equal at least 30% (40% in the case of Members that have the older form of RUS loan documents) of its total assets, or (2) distributions do not exceed 25% of the margins and patronage capital received by the Member in the preceding year and equity is at least 20% (the 20% equity requirement does not apply to Members that have the older form of RUS loan documents). (See "Members' Relationship with RUS" below.)

    Oglethorpe is a membership corporation, and the Members are not subsidiaries of Oglethorpe. Except with respect to the obligations of the Members under each Member's Wholesale Power Contract with Oglethorpe and Oglethorpe's rights under such Contracts to receive payment for power and energy supplied, Oglethorpe has no legal interest in, or obligations in respect of, any of the assets, liabilities, equity, revenues or margins of the Members. (See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts.") The revenues of the Members are not pledged as security to Oglethorpe but are the source from which moneys are derived by the Members to pay for power supplied by Oglethorpe under the Wholesale Power Contracts. Revenues of the Members are, however, pledged under their respective RUS mortgages or loan documents with other lenders.

Rate Regulation of Members

    Through provisions in the loan documents securing loans to the Members, RUS exercises control and supervision over the rates for the sale of power of the Members that borrow from it. The RUS mortgages of such Members require them to design rates with a view to maintaining an average Times Interest Earned Ratio and an average Debt Service Coverage Ratio of not less than 1.25 and an Operating Times Interest Earned Ratio and an Operating Debt Service Coverage Ratio of not less than 1.10, in each case for the two highest out of every three successive years.

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    The Georgia Electric Membership Corporation Act, under which each of the Members was formed, requires the Members to operate on a not-for-profit basis and to set rates at levels that are sufficient to recover their costs and to provide for reasonable reserves. The setting of rates by the Members is not subject to approval by any federal or state agency or authority other than RUS, but the Territorial Act prohibits the Members from unreasonable discrimination in the setting of rates, charges, service rules or regulations and requires the Members to obtain GPSC approval of long-term borrowings.

    Cobb EMC, Diverse Power Incorporated, an EMC, Mitchell EMC, Oconee EMC, Snapping Shoals EMC and Walton EMC have paid their RUS indebtedness and are no longer RUS borrowers. Each of these Members now has a rate covenant with its current lender. Other Members may also pursue this option. To the extent that a Member who is not an RUS borrower engages in wholesale sales or transmission in interstate commerce, it would be subject to regulation by FERC under the Federal Power Act.

Members' Relationship with RUS

    Through provisions in the loan documents securing loans to the Members, RUS also exercises control and supervision over the Members that borrow from it in such areas as accounting, other borrowings, construction and acquisition of facilities, and the purchase and sale of power.

    Historically, federal loan programs providing direct loans from RUS to electric cooperatives have been a major source of funding for the Members. Under the current RUS loan programs, interest rates are based on either Treasury rates or rates being paid on municipal bonds with comparable maturities. Certain borrowers with either low consumer density or higher-than-average rates and lower-than-average consumer income are eligible for special loans at 5%. Distribution borrowers are also eligible for loans made by FFB or other lenders and guaranteed by RUS. However, the availability and magnitude of RUS direct and guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, RUS loan funds are subject to increased uncertainty because of recent budgetary pressures faced by Congress. Oglethorpe cannot predict the amount or cost of RUS direct and guaranteed loans that may be available to the Members in the future.

Members' Relationships with GTC and GSOC

    GTC provides transmission services to the Members for delivery of the Members' power purchases from Oglethorpe and other power suppliers. GTC and the Members have entered into Member Transmission Service Agreements (the "MTSAs") under which GTC provides transmission service to the Members pursuant to a transmission tariff. The MTSAs have a minimum term for network service for current load until December 31, 2025. After an initial term ending in 2006, load growth above 1995 requirements may, with notice to GTC, be served by others. The MTSAs provide that if a Member elects to purchase a part of its network service elsewhere, it must pay appropriate stranded costs to protect the other Members from any rate increase that could otherwise occur. Under the MTSAs, Members have the right to design, construct and own new distribution substations. GTC has asked its members to execute extensions to the MTSAs to extend the terms to 2040. The extensions will also include similar opportunities for transmission service to be provided by others.

    GSOC has contracts with each of its members, including OPC and GTC, to provide to them the services that it purchases from GPC under the Control Area Compact, which Oglethorpe co-signed with GSOC. GSOC also provides operation services for the benefit of the Members through agreements with Oglethorpe, including dispatch of Oglethorpe's resources and other power supply resources owned by the Members.

    For additional information about the Members' relationship with GSOC, see "OGLETHORPE POWER CORPORATION – Relationship with GSOC."

Member Power Supply Resources

Oglethorpe Power Corporation

    Oglethorpe currently supplies a substantial portion of the Members' requirements. Each Member has a take-or-pay, fixed percentage capacity responsibility for all of Oglethorpe's existing resources. (See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts.") The Members are satisfying all of their requirements above Oglethorpe purchase obligations with purchases from other suppliers as described below.

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Contracts with SEPA

    The Members purchase hydroelectric power from the Southeastern Power Administration ("SEPA") under contracts that extend until 2016. In 2004, the aggregate SEPA allocation to the Members was 562 MW plus associated energy. Each Member must schedule its energy allocation, and each Member has designated Oglethorpe to perform this function. Pursuant to a separate agreement, Oglethorpe will schedule, through GSOC, the Members' SEPA power deliveries. Further, each Member may be required, if certain conditions are met, to contribute funds for capital improvements for Corps of Engineers projects from which its allocation is derived in order to retain the allocation.

Smarr EMC

    The Members participating in the facilities owned by Smarr EMC purchase the output of those facilities pursuant to long-term, take-or-pay power purchase agreements. Smarr EMC owns Smarr Energy Facility, a two-unit, 217 MW gas-fired combustion turbine facility (with 35 participating Members), and Sewell Creek Energy Facility, a four-unit, 492 MW gas-fired combustion turbine facility (with 31 participating Members). Smarr Energy Facility began commercial operation in June 1999, and Sewell Creek Energy Facility began commercial operation in June 2000.

GPC Block Purchase

    Twenty-nine Members have entered into long-term power supply contracts with GPC under which they will purchase an aggregate of 675 MW of capacity and associated energy. Delivery under the agreements began January 1, 2005.

Other Member Resources

    Members are obtaining their other power supply requirements from various sources. Thirty Members have entered into contracts with third parties for all of their incremental power requirements, with remaining terms ranging from 6 to 13 years. The other Members use a portfolio of power purchase contracts to meet their requirements.

    Oglethorpe has not undertaken to obtain a complete list of Member power supply resources. Any of the Members may have committed or may commit to additional power supply obligations not described above.

    For further information about Members' activities relating to their power supply planning, see "OGLETHORPE POWER CORPORATION – Competition."

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ENVIRONMENTAL AND OTHER REGULATION

General

    As is typical for electric utilities, Oglethorpe is subject to various federal, state and local air and water quality requirements which, among other things, regulate emissions of pollutants, such as particulate matter, sulfur dioxide and nitrogen oxides into the air and discharges of other pollutants, including heat, into waters of the United States. Oglethorpe is also subject to federal, state and local waste disposal requirements that regulate the manner of transportation, storage and disposal of various types of waste.

    In general, environmental requirements are becoming increasingly stringent. New requirements may substantially increase the cost of electric service, by requiring changes in the design or operation of existing facilities or changes or delays in the location, design, construction or operation of new facilities. Failure to comply with these requirements could result in the imposition of civil and criminal penalties as well as the complete shutdown of individual generating units not in compliance. Oglethorpe cannot provide assurance that it will always be in compliance with current and future regulations.

    Compliance with environmental standards will continue to be reflected in Oglethorpe's capital expenditures and operating costs. Oglethorpe made environmental-related capital expenditures of $4 million in 2004 and forecasts expenditures of approximately $6 million, $10 million and $43 million in 2005, 2006 and 2007, respectively, to maintain and achieve compliance with current and anticipated environmental requirements. For a further discussion of expected future capital expenditures to comply with environmental requirements and regulations, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements."

Clean Air Act

    Environmental concerns of the public, the scientific community and Congress have resulted in the enactment of legislation that has had and will continue to have a significant impact on the electric utility industry. The most significant environmental legislation applicable to Oglethorpe is the Clean Air Act. One of the purposes of the Clean Air Act is to improve air quality by reducing the emissions of sulfur dioxide and nitrogen oxides from affected utility units, which include the coal-fired units at Plants Wansley and Scherer.

    Sulfur dioxide reductions are being imposed through a sulfur dioxide emission allowance trading program. Allowances are issued by the U.S. Environmental Protection Agency ("EPA") to impose stringent reductions on all affected units. The aggregate emissions of sulfur dioxide from all affected units are now capped at 8.9 million tons per year. Emission allowances, each of which gives the holder the authority to emit one ton of sulfur dioxide during a particular calendar year or thereafter, are issued 30 years in advance and are transferable. Oglethorpe is now complying with this program by using lower-sulfur fuel, coupled with the use of emission allowances (issued, banked or purchased, if needed). Installation of flue gas desulfurization equipment ("scrubbers") remains a possibility for compliance in the future, as is discussed in more detail below.

    Reductions in nitrogen oxides emissions are also being imposed, under Georgia's State Implementation Plan as part of Georgia's effort to bring the metropolitan Atlanta area, currently classified as a "severe nonattainment area" pursuant to the 1-hour National Ambient Air Quality Standards ("NAAQS") for ozone, into attainment. As part of this Plan, both Plants Wansley and Scherer were included in nitrogen oxides emissions averaging plans, which required the co-owners of the plants to install new control equipment at both plants. Significant reductions in nitrogen oxides emissions were achieved, due to the selective catalytic reduction systems installed at Plant Wansley and the separated overfire air systems installed at Plant Scherer.

    A number of recently finalized regulations, proposed regulations and other actions could result in more stringent controls on all emissions, including utility emissions. The actions that appear to be the most significant are described below.

    EPA has tightened the NAAQS for both ozone and fine particulate matter, an action that could affect any source that emits nitrogen oxides and sulfur dioxide, including utility units. With respect to the ozone NAAQS, EPA must harmonize provisions in the Clean Air Act imposing the old 1-hour ozone NAAQS with EPA's new 8-hour standard before implementing the new standard. Based on the last three years of monitoring data, the State of Georgia believes that the Atlanta area has now attained the 1-hour ozone NAAQS

13

and, therefore, on February 1, 2005, applied to EPA for redesignation as attainment.

    EPA has designated areas as attainment or nonattainment with these 8-hour NAAQSs. It also has published a portion of the rules implementing the new 8-hour NAAQS. The Atlanta ozone nonattainment area has been expanded from the original 13 counties (for the 1-hour NAAQS) to a 20-county area (for the 8-hour NAAQS). Macon, which has been separately designated as an 8-hour ozone nonattainment area, includes Plant Scherer within its boundaries. Under the implementation provisions of the new 2004 rule, EPA announced that the 1-hour ozone standard will be revoked on June 15, 2005. For the new 8-hour ozone nonattainment areas, state implementation plans, including new emission control regulations necessary to bring those areas into attainment could be required as early as 2007. Therefore, further reductions of nitrogen oxides from Plants Wansley and/or Scherer may be required. Some or all of these reductions may come through implementation of the interstate air quality rulemaking discussed below. The impact of these new designations will depend on the development and implementation of any other applicable regulations as needed for attainment and cannot be determined at this time.

    In January 2005, EPA issued its final nonattainment designations for the fine particulate matter NAAQS. Plants Wansley and Scherer were included in the designated areas. EPA plans to propose a fine particulate matter implementation rule in 2005 and to finalize such rule in 2006. In order to achieve compliance by 2010, if no extensions are granted, state implementation plans addressing the nonattainment designations may be due by 2008 and could require reductions in sulfur dioxide and nitrogen oxide emissions from power plants. The impact of the fine particulate matter designations will depend on the development and implementation of applicable state implementation plans and associated regulations and therefore cannot be determined at this time. In addition, the possibility exists that the fine particulate matter NAAQS may be tightened even further in the coming years, which could lead to more stringent controls for sulfur dioxide and nitrogen oxide emissions on power plants.

    In 1998, EPA issued a regulation calling for regional reductions in nitrogen oxides emissions from 22 states, including Georgia, which imposed a fixed cap on nitrogen oxides emissions from such states. In April 2004, EPA finalized a new regional nitrogen oxides reduction rule for Georgia, which specified a May 2007 compliance deadline. In October 2004, however, EPA announced that it would stay the implementation of this rule for Georgia, while it conducts a rulemaking to consider certain issues raised in a petition for reconsideration of the April 2004 rule. Georgia's implementation plan for this regulation will depend on how this proposed rulemaking is finalized. Therefore, it is not yet known what additional controls, if any, will be needed at Plants Wansley and/or Scherer to comply with this regional nitrogen oxides reduction program. However, to achieve the reductions that may be necessary under these rules, the co-owners of Plant Scherer converted Scherer Units No. 1 and No. 2 from bituminous coal to sub-bituminous coal, substantially reducing the nitrogen oxides emissions from these units.

    In March 2005, EPA finalized a clean air interstate rule for ozone and fine particulate matter that will require emissions reductions in sulfur dioxide and nitrogen oxides in most eastern states, including Georgia, by establishing a market-based cap and trading program with emission budget caps for each affected state. Although announced as final, the rule is still subject to challenge. One possible result of the rule may be to require year round reductions in emissions of sulfur dioxide and nitrogen oxides from power plants. The caps would be implemented in two phases. The first phase for nitrogen oxides caps would become effective in 2009 and for sulfur dioxide caps in 2010, each followed by a second phase in 2015. The rule may require additional controls at Plants Wansley and/or Scherer in order to comply with the state implementation plan to be developed to meet emission caps established in the rule for Georgia. The rule could affect Georgia's plans for attaining the NAAQS for ozone and fine particulate matter discussed above.

    In 1999, EPA promulgated a new regional haze rule, which would have affected certain sources that emit nitrogen oxides or sulfur dioxide and that may contribute to the degradation of visibility in mandatory federal Class I areas, including some utility units. As a result of challenges to this rule, however, the Court of Appeals has vacated part of the rule, remanding it back to EPA for further consideration consistent with its opinion. In response, EPA proposed revised rules in May 2004, which it announced it plans to finalize in April 2005. Until such rules are finalized and implemented by the State of Georgia, Oglethorpe will not know what controls, if any, must be installed at Plants Wansley and/or Scherer to comply with this rule.

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    Although EPA had decided not to impose a new NAAQS for sulfur dioxide, that decision has been remanded to EPA for further rulemaking, so it is still possible that a new short-term standard for sulfur dioxide could be established.

    In March 2005, EPA finalized a regulation that would control emissions of mercury, by creating a market-based cap and trade program that would reduce emissions of mercury in two phases, with the first phase becoming effective in 2010 and the second in 2018. Although announced as final, the rule is still subject to challenge. The rule could require additional controls at Plants Wansley and/or Scherer in order to comply with the state implementation plan to be developed to meet emission caps established in the rule for Georgia.

    Because (1) several of these proposed or final Clean Air Act regulations could require control of the same emissions, (2) the compliance requirements are uncertain, and (3) specific control technologies affect multiple emissions, Oglethorpe cannot determine the aggregate effect of these or future regulations. For a discussion of the factors that will affect future compliance decisions, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures."

    Congress is currently considering legislation to amend the Clean Air Act, some versions of which may impose more stringent emissions limitations on power plants. The impact of any amendment would depend upon the specific requirements enacted and cannot be determined at this time.

    Domestic efforts to limit emissions of carbon dioxide from power plants are increasing. For example, 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 in July 2004. The complaint alleges that the companies' emissions of carbon dioxide contribute to global warming, which the Plaintiffs claim is a public nuisance. Although not named in the complaint, Oglethorpe believes this claim is without merit. While the outcome of this matter cannot be determined at this time, an adverse judgment could result in substantial capital expenditures at Plants Wansley and/or Scherer, which Oglethorpe co-owns with Georgia Power Company ("GPC"), a subsidiary of the Southern Company.

    Pursuant to the Framework Convention On Climate Change, international discussions for limiting emissions of carbon dioxide continue. Whether such discussions will lead to limits for carbon dioxide in the U.S. in the future, through ratification of the Kyoto Protocol, other treaties or domestic legislation is unknown. Should such reductions be imposed in the future, substantial capital expenditures could be required at Oglethorpe's fossil fuel-fired facilities.

    On November 3, 1999, the United States Justice Department, on behalf of EPA, filed lawsuits against GPC and some of its affiliates, as well as other utilities. The lawsuits allege violations of the new source review provisions and the new source performance standards of the Clean Air Act at, among other facilities, Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named in the lawsuits and Oglethorpe does not have an ownership interest in the named units of Plant Scherer. However, Oglethorpe can give no assurance that units in which Oglethorpe has an ownership interest will not be affected by this or a related lawsuit in the future. The resolution of this matter is highly uncertain at this time, as is any responsibility of Oglethorpe for a share of any penalties and capital costs required to remedy any violations at facilities co-owned by Oglethorpe.

    In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forest Watch and one individual filed suit in Federal Court in Georgia against GPC alleging violations of the Clean Air Act at Plant Wansley. The complaint alleges violations of opacity limits at both the coal fired units, in which Oglethorpe is a co-owner, and other violations at several combined cycle units in which Oglethorpe does not have an ownership interest. This civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project and attorneys' fees. In December 2004, the U.S. District Court for the Northern District of Georgia issued an Order holding GPC liable for certain violations of the opacity limits at the coal-fired units. However, in March 2005 the U.S. Court of Appeals for the Eleventh Circuit allowed an immediate appeal of the Court's Order. While Oglethorpe believes that Plant Wansley has complied with applicable laws and regulations, resolution of this matter is uncertain at this time, as is any responsibility of Oglethorpe for a share of any penalties or other costs that might be assessed against GPC.

    In January 2003, the Sierra Club appealed an unsuccessful challenge to an air operating permit for Chattahoochee to the United States Court of Appeals

15

for the Eleventh Circuit. Oglethorpe acquired this facility in the second quarter of 2003. (See "OGLETHORPE POWER CORPORATION – Power Supply Business.") Oglethorpe intervened in the appeal on behalf of EPA. In May 2004, the Court ruled in favor of the Sierra Club, invalidating EPA's denial of the petition and remanding the matter to EPA for further consideration. Although Oglethorpe believes that the order does not affect facility operations pending further consideration and that a favorable outcome in this matter is likely, an unfavorable ruling could temporarily affect the ability of the facility to continue operations.

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

    Compliance with the requirements of the Clean Air Act may also require increased capital or operating expenses on the part of GPC. Any increases in GPC's capital or operating expenses may cause an increase in the cost of power purchased from GPC. (See "OGLETHORPE'S POWER SUPPLY RESOURCES – Power Purchase and Sale Arrangements – Power Purchases" and "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources – GPC Block Purchase.")

Other Environmental Regulation

    EPA determined in 2000 that although coal ash should continue to be considered non-hazardous under the Resource Conservation and Recovery Act, national regulations are warranted. Depending on the outcome of such rulemaking, which is now expected in 2007, substantial additional costs for the management of these wastes might be required of Oglethorpe.

    Under the Clean Water Act, EPA and state environmental agencies are developing total maximum daily loads ("TMDLs") for certain impaired state waters. The establishment of TMDLs and/or additional measures to control non-point source pollution may result in a tightening of limits in water discharge permits for power plants, including Plants Wansley and Scherer. As the impact will depend on the actual TMDLs and the corresponding permit limitations that are established, the effects of such developments cannot be predicted at this time.

    Oglethorpe is 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. Oglethorpe does not believe that compliance with these statutes and regulations will have a material impact on its 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 Oglethorpe's operations. Although compliance with new environmental legislation could have a significant impact on Oglethorpe, those impacts cannot be fully determined at this time and would depend in part on the final legislation and the development of implementing regulations.

    Oglethorpe, or generating facilities in which Oglethorpe has 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. Oglethorpe cannot predict the outcome of current or future actions, the responsibility of Oglethorpe for a share of any damages awarded or any impact on facility operations. Oglethorpe, however, does not believe that the current actions will have a material adverse effect on its financial position or results of operations.

Nuclear Regulation

    Oglethorpe is subject to the provisions of the Atomic Energy Act of 1954, as amended (the "Atomic Energy Act"), which vests jurisdiction in the Nuclear Regulatory Commission ("NRC") 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 NRC 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 NRC. All aspects of the operation and maintenance of nuclear power plants are regulated by the NRC. From time to time, new NRC regulations require changes in the design, operation and maintenance of existing nuclear reactors. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and

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the operation of a nuclear unit may be suspended if the NRC 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 2027 and 2029, respectively. The licenses for Plant Hatch were extended to their current expiration dates in January 2002.

    Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the federal government has the regulatory responsibility for the final disposition 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 ("DOE") for such material. These contracts require each such owner to pay a fee, which is currently one dollar per MWh for the net electricity generated and sold by each of its reactors.

    Contracts with DOE have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. DOE failed to begin disposing of spent fuel in 1998 as required by the contracts, and GPC, as agent for the co-owners of the plants, is pursuing legal remedies against DOE for breach of contract.

    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. Oglethorpe expects 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 Financial Statements.)

    For information concerning nuclear insurance, see Note 8 of Notes to Financial Statements. For information regarding NRC's regulation relating to decommissioning of nuclear facilities and regarding DOE's assessments pursuant to the Energy Policy Act for decontamination and decommissioning of nuclear fuel enrichment facilities, see Note 1 of Notes to Financial Statements.

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ITEM 2. PROPERTIES

Generating Facilities

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

⁽¹⁾

These plants do not operate under operating licenses similar to those granted to nuclear units by the NRC and to hydroelectric plants by FERC.

⁽²⁾

Nominal plant capacity identified in the Power Purchase and Sale Agreement with Doyle I, LLC. (See "The Plant Agreements – Doyle" below.)

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Plant Performance

    The following table sets forth certain operating performance information of each of Oglethorpe's generating facilities:

⁽¹⁾

Equivalent Availability is a measure of the percentage of time that a unit was available to generate if called upon, adjusted for periods when the unit is partially derated from the "maximum dependable capacity" rating.

⁽²⁾

Capacity Factor is a measure of the output of a unit as a percentage of the maximum output, based on the "maximum dependable capacity" rating, over the period of measure.

⁽³⁾

Plant Scherer's relatively low performance in 2003 was due to the outage time required for the conversion to use sub-bituminous coal, as described below.

⁽⁴⁾

Rocky Mountain, Doyle and Talbot primarily operate as peaking plants, which results in low capacity factors.

⁽⁵⁾

Equivalent Availability for each of Doyle's 5 units is measured only during the period May 15 – September 15, reflecting the contractual availability commitment of Doyle I, LLC. The units may be dispatched by Oglethorpe during other periods if the units are available.

⁽⁶⁾

Talbot Unit Nos. 1-4 began commercial operation in April-June 2002 and Unit Nos. 5-6 began commercial operation in May 2003. Chattahoochee began commercial operation in February 2003.

    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, from coal mines in the eastern United States. As of February 28, 2005, Oglethorpe had a 52-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, 2005, Oglethorpe's coal stockpile at Plant Scherer contained a 24-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming. Oglethorpe's coal inventory at Plant Scherer is lower than normal due to recently developed rail transportation bottlenecks. Oglethorpe and the other co-owners are working with the rail transportation supplier to relieve the problem. Failure to relieve the problem may require Oglethope to burn higher cost fuel at its other generating plants or require the Members to purchase energy from higher cost sources.

    Oglethorpe currently leases approximately 1,200 rail cars to transport coal to Plants Scherer and Wansley.

    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 GPC and (ii) to procure separately long-term coal purchases. Oglethorpe separately dispatches Plant Scherer and Plant Wansley, but continues to use GPC as its agent for fuel procurement.

    For information relating to the impact that the Clean Air Act may have on Oglethorpe, see "BUSINESS – ENVIRONMENTAL AND OTHER REGULATION – Clean Air Act."

    Nuclear Fuel.    GPC, as operating agent, has the responsibility to procure nuclear fuel for Plants Hatch and Vogtle. GPC has contracted with Southern Nuclear Operating Company ("SNOC") to operate these plants, including nuclear fuel procurement. SNOC employs both spot purchases and long-term contracts to satisfy nuclear fuel requirements. The nuclear fuel supply and related services are expected to be adequate to satisfy current and future nuclear generation requirements.

    Natural Gas.    Oglethorpe purchases the natural gas, including transportation and other related services, needed to operate Doyle, Talbot and Chattahoochee and the combustion turbines owned by Hartwell Energy Limited Partnership. Oglethorpe purchases natural gas in the spot market and under agreements at indexed prices. Oglethorpe has entered into hedge agreements to manage a portion of its exposure to fluctuations in the market price of natural gas. Oglethorpe manages exposure to such risks only with respect to Members that elect to receive such services. Oglethorpe purchases transportation under long-term firm and short-term firm and non-firm contracts. (See "QUALITATIVE AND QUANTITATIVE 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 Oglethorpe, GPC, MEAG and Dalton, and Rocky Mountain is co-owned by Oglethorpe and GPC. Each such co-owner owns or leases undivided interests in the amounts shown in the following table (which excludes the Plant Wansley combustion turbine). Oglethorpe is the operating agent for Rocky Mountain. GPC is the operating agent for each of the other plants.

⁽¹⁾

Based on nameplate ratings.

Georgia Power Company

    GPC is a wholly owned subsidiary of The Southern Company, a registered holding company under the Public Utility Holding Company Act, and is engaged primarily in the generation and purchase of electric energy and the transmission, distribution and sale of such energy. GPC 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 Oglethorpe, MEAG and two municipalities. GPC is the largest supplier of electric energy in the State of Georgia. (See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with GPC.") GPC is subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and, in accordance therewith, files reports and other information with the Commission.

Municipal Electric Authority of Georgia

    MEAG, an instrumentality of the State of Georgia, was created for the purpose of providing electric capacity and energy to those political subdivisions of the State of Georgia that owned and operated electric distribution systems at that time. MEAG, also known as MEAG Power, has wholesale power sales contracts with each of its 49 participants (including 48 cities and one county in the State of Georgia) that extend through 2054. Such political subdivisions, located in 39 of the State's 159 counties, collectively serve approximately 300,000 electric consumers (meters).

City of Dalton, Georgia

    The City of Dalton, located in northwest Georgia, supplies electric capacity and energy to consumers in Dalton, and presently serves more than 10,000 residential, commercial and industrial customers.

The Plant Agreements

Hatch, Wansley, Vogtle and Scherer

    Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley, Vogtle and Scherer are contained in a number of contracts between Oglethorpe and GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four Purchase and Ownership Participation Agreements ("Ownership Agreements") under which it acquired from GPC 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"). Oglethorpe has 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 Oglethorpe and GPC. The Ownership Agreements and Operating Agreements relating to Plants Vogtle and Scherer are agreements among Oglethorpe, GPC, MEAG and Dalton. The parties to each Ownership Agreement and Operating

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Agreement are referred to as "participants" with respect to each such agreement.

    In 1985, in four transactions, Oglethorpe sold its entire 60% undivided ownership interest in Scherer Unit No. 2 to four separate owner trusts (the "Lessors") established by four different institutional investors. Oglethorpe retained all of its rights and obligations as a participant under the Ownership and Operating Agreements relating to Scherer Unit No. 2 for the term of the leases. Oglethorpe's leases expire in 2013, with options to renew for a total of 8.5 years. Oglethorpe also has fair market value purchase options at specified dates, including 2013 and the end of lease renewal terms. These transactions are treated as capital leases by Oglethorpe for financial reporting purposes. (See Note 4 of Notes to Financial Statements.) (In the following discussion, references to participants "owning" a specified percentage of interests include Oglethorpe's rights as a deemed owner with respect to its leased interests in Scherer Unit No. 2.)

    The Ownership Agreements appoint GPC 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 Scherer Common Facilities. Each Operating Agreement gives GPC, 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, GPC is required to comply with prudent utility practices. GPC's liabilities with respect to its duties under the Ownership and Operating Agreements are limited by the terms thereof.

    Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage of capital costs of the respective plants, as incurred, equal to the percentage interest which it owns or leases at each plant. GPC has responsibility for budgeting capital expenditures for Scherer Units No. 1 and 2 subject to certain limited rights of the participants to disapprove capital budgets proposed by GPC and to substitute alternative capital budgets. GPC has responsibility for budgeting capital expenditures for Plants Hatch and Vogtle, subject to the right of any co-owner 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 GPC to contract with a third party for the operation of the nuclear units. In March 1997, GPC designated SNOC as the operator of Plants Hatch and Vogtle, pursuant to the Nuclear Operating Agreement between GPC and SNOC, 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 GPC's role as agent with respect to Plant Scherer.

    The Operating Agreements provide that Oglethorpe is entitled to a percentage of the net capacity and net energy output of each plant or unit equal to its percentage undivided interest owned or leased in such plant or unit. GPC, as agent, schedules and dispatches Plants Hatch and Vogtle. Oglethorpe separately dispatches its ownership share of Scherer Units No. 1 and No. 2 and of Plant Wansley. (See "Fuel Supply" above.)

    For Plants Hatch and Vogtle, each participant is responsible for a percentage of Operating Costs (as defined in the Operating Agreements) and fuel costs of each plant or unit equal to the percentage of its undivided interest which is owned or leased in such plant or unit. For Scherer Units No. 1 and No. 2 and for Plant Wansley, each party is responsible for its fuel costs and for variable Operating Costs in proportion to the net energy output for its ownership interest, and is responsible for a percentage of fixed Operating Costs equal to the percentage of its undivided interest which is owned or leased in such plant or unit. GPC is required to furnish budgets for Operating Costs, fuel plans and scheduled maintenance plans. In the case of Scherer Units No. 1 and No. 2, the participants have limited rights to disapprove such budgets proposed by

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GPC 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 Agreement for Plant Hatch will remain in effect with respect to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. Oglethorpe has entered into an agreement with GPC, subject to RUS approval, to extend the Operating Agreement for so long as an NRC operating license exists for each unit. (See "ENVIRONMENTAL AND OTHER REGULATION – Nuclear Regulation.") The Operating Agreement for Plant Vogtle will remain in effect with respect to each unit at Plant Vogtle until 2018. 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, GPC 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.

Rocky Mountain

    Oglethorpe owns a 74.61% undivided interest in Rocky Mountain and GPC owns the remaining 25.39% undivided interest.

    The Rocky Mountain Pumped Storage Hydroelectric Ownership Participation Agreement, by and between Oglethorpe and GPC (the "Rocky Mountain Ownership Agreement") appoints Oglethorpe 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 Oglethorpe, 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 the 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. Oglethorpe and GPC have each elected to schedule separately their 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, Oglethorpe completed lease transactions for its 74.61% undivided ownership interest in Rocky Mountain. The lease transactions are characterized as a sale and leaseback for income tax purposes, but not for financial reporting purposes. Under the terms of these transactions, Oglethorpe leased the facility to three institutional investors for the useful life of the facility, who in turn leased it back to Oglethorpe for a term of 30 years. Oglethorpe will continue to control and operate Rocky Mountain during the leaseback term. Oglethorpe intends to exercise its fixed price purchase option at the end of the leaseback period so as to retain all other rights of ownership with respect to the plant if it is advantageous for Oglethorpe to exercise such option. 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."

Doyle

    Oglethorpe has an agreement with Doyle I LLC, a limited liability company owned by one of Oglethorpe's Members, Walton EMC, to purchase the output of a gas-fired combustion turbine generating facility with a nominal contract rating of 325 MW over a 15-year term. Delivery commenced May 15, 2000.

    During the term of the agreement, Oglethorpe has the right and obligation to purchase all of the capacity and energy from the facility. Oglethorpe is obligated to pay to Doyle I, LLC each month a capacity charge based on

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a performance rating and an energy charge equal to all costs of operating the facility. Oglethorpe is also obligated to pay the actual operation and maintenance costs and the costs of capital improvements. Oglethorpe is responsible for supplying all natural gas necessary to operate the facility. Oglethorpe has 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, Oglethorpe may dispatch the facility at other times to the extent that the facility is available.

    Oglethorpe has an option to purchase the facility at the end of the term of the agreement at a fixed price. This agreement is treated as a capital lease of the facility by Oglethorpe for financial reporting purposes. (See Note 4 of Notes to Financial Statements.)

ITEM 3. LEGAL PROCEEDINGS

       Oglethorpe is a party to various actions and proceedings incidental to its 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 Oglethorpe's management, after consultation with counsel, should not in the aggregate have a material adverse effect on the financial position or results of operations of Oglethorpe.

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

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

       Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

       Not Applicable.

ITEM 6. SELECTED FINANCIAL DATA (UNAUDITED)

       The following table presents selected historical financial data of Oglethorpe. The financial data presented as of the end of and for each year in the five-year period ended December 31, 2004, have been derived from the audited financial statements of Oglethorpe. This data should be read in conjunction with the financial statements of Oglethorpe and the notes thereto included in Item 8 and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" in Item 7.

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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 on Form 10-K contains forward-looking statements, including statements regarding, among other items, (i) anticipated trends in the business of Oglethorpe, (ii) Oglethorpe's future power supply requirements, resources and arrangements, (iii) Oglethorpe's 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 Oglethorpe's current expectations and are subject to a number of risks and uncertainties, some of which are beyond Oglethorpe's control. For some of the factors that could cause actual results to differ materially from those anticipated by these forward-looking statements, see "Accounting Policies – Critical Accounting Policies" below, "BUSINESS – OGLETHORPE POWER CORPORATION – Competition" and "ENVIRONMENTAL AND OTHER REGULATION." In light of these risks and uncertainties, Oglethorpe can give no assurance that events anticipated by the forward-looking statements contained in this Annual Report will in fact transpire.

Executive Overview

    Oglethorpe is a not-for-profit electric cooperative whose principal business is providing wholesale electric service to 38 Members. Consequently, substantially all of Oglethorpe's revenues and cash flow is derived from sales to the Members pursuant to long-term, take-or-pay wholesale power contracts. These contracts obligate the Members jointly and severally to pay all of Oglethorpe's costs and expenses associated with owning and operating its power supply business. To that end, Oglethorpe's 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 Oglethorpe's Margins for Interest Ratio rate covenant) are carefully managed throughout the year to ensure that sufficient capacity-related revenues are produced. This rate structure provides Oglethorpe with the ability to manage its revenues to assure full recovery of its costs in rates and has resulted in a consistent record of meeting all of its financial requirements. The year 2004 was no exception as revenues were sufficient, but only sufficient, to recover all costs and to satisfy all debt service obligations and financial covenants, including Oglethorpe's annual margin requirement.

    The existing base term of Oglethorpe's Wholesale Power Contract with each Member runs through 2025. The Oglethorpe Board has approved an extension of the base term by an additional 25 years, which would be sufficient to substantially cover the projected remaining useful lives of all of Oglethorpe's assets. The Members are supportive of this initiative. If the Members approve the extension, it is likely that Oglethorpe would then consider the refinancing of a portion of its long-term debt to better match debt amortization to the projected useful lives of its assets.

    Effective January 1, 2005, one of Oglethorpe's Members, Flint EMC, withdrew from membership in Oglethorpe, thereby reducing the number of Members served by Oglethorpe from 39 to 38. Simultaneous with its withdrawal, Flint EMC, with the consent of the Oglethorpe Board of Directors, assigned its Wholesale Power Contract with Oglethorpe to another Oglethorpe Member, Cobb EMC. Cobb EMC, with the approval of the Oglethorpe Board of Directors, subsequently reallocated the power supply resources covered by this contract among itself and six other Oglethorpe Members. Oglethorpe believes that this withdrawal, assignment and reallocation does not and will not, have a material adverse effect on its financial condition or results of operations.

    In 2004, Oglethorpe continued to maintain a strong liquidity position that is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and a commercial paper program. The reliability of the commercial paper program was bolstered in 2004 when the program's back-up lines of credit were renewed for three-year terms instead of the customary one-year term. Unrestricted available liquidity at year-end was $561 million.

    In 2003, Oglethorpe entered into agreements with the Members that clarified and, in some instances, redefined its relationship with the Members. Among other things, the agreements specify the types of future services that Oglethorpe may provide to its Members as well as the terms and conditions under which those services can be

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provided. In particular, the agreements address the circumstances under which Oglethorpe can directly obligate itself or otherwise utilize its credit to support a service when less than all of Oglethorpe's Members benefit from that service. These limitations are significant to Oglethorpe's Members because they are jointly and severally liable for Oglethorpe's obligations even though they may not all benefit from a particular service.

    These member agreements make it explicit that the Members are directly responsible for the planning and procurement of their future power supply requirements. As a result of these member agreements, Oglethorpe will be limited in its ability to develop or obtain new power supply resources to assist the Members with their future, incremental power requirements. This is particularly relevant since the Members have had to plan and implement power supply options to replace a portion of the energy that was being provided by two significant power marketer agreements that will terminate by the end of March 2005. While Oglethorpe resources (generating facilities and power purchase contracts) have been providing more than 90% of the Members' requirements, with the terminations of the power marketer agreement with LG&E Energy Marketing Inc. ("LEM") at the end of 2004 and the power marketer agreement with Morgan Stanley Capital Group Inc. ("Morgan Stanley") at the end of March 2005, Oglethorpe resources will only provide approximately 70% of the Members' requirements. At the end of 2004, plans by the Members to replace the portion of energy being provided by LEM were implemented smoothly. This is also expected to be the case when the Morgan Stanley agreement terminates at the end of March.

    The absence of these two agreements from Oglethorpe's power supply portfolio will, however, result in an increase to the average cost of power that will be supplied by Oglethorpe to the Members in the future. There are two reasons for this. First, the energy that was provided pursuant to these two agreements was at a very favorable cost to Oglethorpe. But, more importantly, because Oglethorpe will be selling approximately 24% less energy to its Members, spreading Oglethorpe's fixed costs (which remain relatively unchanged) over fewer MWhs sold has the effect of increasing Oglethorpe's average cost of power. It is not unlikely that Oglethorpe's average power cost will increase by approximately 20% or more.

    As a consequence of the new agreements with its Members, Oglethorpe's business focus has shifted away from power supply planning and procurement and is now firmly concentrated on managing its existing resources with a view to enhancing the value of those resources for their primary beneficiaries – Oglethorpe's Members. Oglethorpe has developed strategies oriented towards (i) protecting the value of its assets from a variety of potential risks, and (ii) enhancing the value of its assets by improving efficiency and effectiveness, reducing costs, and, in some cases, increasing the capacity and/or useful life of its physical assets.

    Responding to changing environmental requirements continues to be a challenge for Oglethorpe. Over the past several years, Oglethorpe has invested in excess of $100 million to maintain compliance with various environmental regulations. The most substantial of these expenditures included the installation of selective catalytic reduction control technologies at Plant Wansley and the conversion of Plant Scherer to permit it to burn Powder River Basin coal. Perhaps the most significant risk to Oglethorpe's ability to maintain competitive power costs in the future is the possibility of additional capital expenditures and increased operational expenses for Plants Wansley and Scherer due to potentially more stringent environmental regulations. While estimates can vary widely, it is not unlikely that Oglethorpe may be required to make significant additional investment over the next 5 to 10 years to maintain environmental compliance.

    From an operational perspective, Oglethorpe will continue to be challenged to provide reliable, cost-effective fuel supply for its generating facilities. A balanced diversity of generating resources by fuel type – nuclear, coal and natural gas – helps mitigate the risk associated with any one type of fuel. The geographic diversity of coal supply – eastern and Powder River Basin – as well as the diversity of suppliers helps reduce risks associated with coal. Ensuring timely and cost-effective transportation of coal is also a high priority for the corporation. Oglethorpe will maintain a high degree of focus on fuel strategies as the cost of fuel, higher or lower, directly impacts the cost of power to its Members.

    Additionally, there are certain risks inherent in Oglethorpe's undivided ownership interests in its two nuclear facilities, Plants Hatch and Vogtle. One such risk is the storage of spent fuel. While the progress towards a national repository is disappointing, both

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facilities have on-site storage capabilities. It is forecasted that the on-site storage capabilities at Plant Hatch can be expanded to accommodate spent fuel through the expected life of the plant. Plant Vogtle is projected to have on-site storage capabilities well into the next decade. Another risk unique to nuclear facilities is the funding for the expected cost of decommissioning. Oglethorpe continues to maintain appropriate balances in its external trust fund based on recent specific site studies, NRC minimum funding requirements and assumptions regarding investment earnings. With respect to operational risk, both plants continue an excellent record of operations with availability and capacity factors exceeding 90% in 2004.

    Oglethorpe continues to believe that nuclear power is an important part of the Members' overall power supply portfolio. Consequently, Oglethorpe remains very interested in the potential development and deployment of the next generation of nuclear facilities and is therefore considering participation in any initiatives that will examine the feasibility of future nuclear generating facilities with the view of preserving the option to participate in any new nuclear generation that might be developed in Georgia.

    Two of Oglethorpe's strengths, its enterprise-wide risk management program and its system of internal controls, will continue to be enhanced in 2005 as Oglethorpe proceeds with implementing the provisions of the Sarbanes-Oxley Act and with refining its corporate compliance processes. Despite the many challenges and risks of operating a power supply corporation, Oglethorpe is well positioned, both financially and operationally, to continue to fulfill its obligations to the Members and third parties.

Summary of Cooperative Operations

Margins and Patronage Capital

    Oglethorpe operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to recover its 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 Oglethorpe's statements of revenues and expenses and patronage capital. Retained net margins are designated on Oglethorpe's balance sheets as patronage capital, which is allocated to each of the Members on the basis of its electricity purchases from Oglethorpe. Since its formation in 1974, Oglethorpe has generated a positive net margin in each year and had a balance of $462 million in patronage capital as of December 31, 2004. Oglethorpe's equity ratio, calculated as patronage capital and membership fees divided by total capitalization, increased from 10.8% at December 31, 2003 to 11.5% at December 31, 2004.

    Patronage capital constitutes the principal equity of Oglethorpe. Any distributions of patronage capital are subject to the discretion of the Board of Directors. However, under the Mortgage Indenture, Oglethorpe is prohibited from making any distribution of patronage capital to the Members if, at the time of or after giving effect to the distribution, (i) an event of default exists under the Mortgage Indenture, (ii) Oglethorpe's equity as of the end of the immediately preceding fiscal quarter is less than 20% of Oglethorpe's total capitalization, or (iii) the aggregate amount expended for distributions on or after the date on which Oglethorpe's equity first reaches 20% of Oglethorpe's total capitalization exceeds 35% of Oglethorpe's aggregate net margins earned after such date. This last restriction, however, will not apply if, after giving effect to such distribution, Oglethorpe's equity as of the end of the immediately preceding fiscal quarter is not less than 30% of Oglethorpe's total capitalization.

Rates and Regulation

    Pursuant to the Wholesale Power Contracts entered into between Oglethorpe and each of the Members, Oglethorpe is required to design capacity and energy rates that generate sufficient revenues to recover all costs, to establish and maintain reasonable margins and to meet its financial coverage requirements. Oglethorpe reviews its capacity rates at least annually to ensure that it meets its net margin goals.

    The rate schedule under the Wholesale Power Contracts implements on a long-term basis the assignment to each Member of responsibility for fixed costs. The monthly charges for capacity and other non-energy charges are based on a rate formula using the Oglethorpe budget. The Board of Directors may adjust these charges during the year through an adjustment to the annual budget. Energy charges are based on actual energy costs, including fuel costs, variable operations and maintenance costs, and purchased energy costs.

    Under the Mortgage Indenture, Oglethorpe is required, subject to any necessary regulatory approval,

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to establish and collect rates that are reasonably expected, together with other revenues of Oglethorpe, 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 equal the sum of (i) Oglethorpe's 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 affiliate or subsidiary of Oglethorpe only if Oglethorpe has received such net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if Oglethorpe has made a payment with respect to such losses or expenditures.

    The rate schedule also includes a prior period adjustment mechanism designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum 1.10 Margins for Interest Ratio would be accrued as of December 31 of the applicable year and collected from the 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 recorded by Oglethorpe, plus amounts necessary to achieve at least the minimum 1.10 Margins for Interest Ratio.

    For 2004, 2003 and 2002, Oglethorpe achieved a Margins for Interest Ratio of 1.10.

    Under the Mortgage Indenture and related loan contract with the RUS, adjustments to Oglethorpe's rates to reflect changes in Oglethorpe's budgets are generally not subject to RUS approval. Changes to the rate schedule under the Wholesale Power Contracts are generally subject to RUS approval. Oglethorpe's rates are not subject to the approval of any other federal or state agency or authority, including GPSC.

Accounting Policies

Basis of Accounting

    Oglethorpe follows generally accepted accounting principles and the practices prescribed in the Uniform System of Accounts of FERC as modified and adopted by the RUS.

Critical Accounting Policies

    Oglethorpe has determined that the following accounting policies are important to understanding the presentation of Oglethorpe's financial condition and results of operations and require assumptions about matters that were uncertain at the time of preparation of Oglethorpe's financial statements. Oglethorpe's management has discussed the development, selection and disclosure of these accounting policies and estimates with the Audit Committee of Oglethorpe's Board of Directors.

Regulatory Assets and Liabilities

    Oglethorpe is subject to the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 permits Oglethorpe to record regulatory assets and regulatory liabilities to reflect future cost recovery or refunds that Oglethorpe has a right to pass through to the Members. At December 31, 2004, Oglethorpe's regulatory assets and liabilities totaled $274 million and $124 million, respectively. (See Note 1 of Notes to Financial Statements.) While Oglethorpe does not currently foresee any event such as competitive or other factors that would make it not probable that Oglethorpe will recover these costs from its Members as future revenues through rates under its Wholesale Power Contracts, if such event occurred, Oglethorpe could no longer apply the provisions of SFAS No. 71, which would require Oglethorpe to eliminate all regulatory assets and liabilities that had been recognized as a charge to its statement of operations and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, Oglethorpe 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 December 2003, the FASB issued Interpretation No. 46R, "Consolidation of Variable Interest Entities – an Interpretation of Accounting Research Bulletin ("ARB") No. 51." This interpretation clarifies the application of ARB No. 51, "Consolidated Financial Statements," to certain entities in which equity investors do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from other parties. Interpretation No. 46R is effective for Oglethorpe as of

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January 1, 2005. This Interpretation has no impact on Oglethorpe's financial statements.

Results of Operations

Power Marketer Arrangements

    Oglethorpe has utilized power marketer arrangements to reduce the cost of power to the Members. Oglethorpe had a power marketer agreement with LEM for approximately 50% of the load requirements of 37 of the Members that terminated as of December 31, 2004. Oglethorpe also has an additional power marketer agreement with Morgan Stanley, which was effective May 1, 1997, with respect to 50% of the 38 Members and Flint EMC's then forecasted load requirements and which terminates on March 31, 2005. The LEM agreement was based on the actual requirements of the participating Members during the contract term, whereas the Morgan Stanley agreement represented a fixed supply obligation. Generally, these arrangements benefited the Members by limiting the risk of unit availability and by providing future needs at a fixed price. Most of Oglethorpe's generating facilities and power purchase arrangements were available for use by LEM and Morgan Stanley. Oglethorpe continued to be responsible for all of the costs of its system resources but received revenue from LEM and Morgan Stanley for the use of the resources.

    The absence of these two agreements from Oglethorpe's power supply portfolio will result in an increase to the average cost of power that will be supplied by Oglethorpe to the Members in the future. There are two reasons for this. First, the energy that was provided pursuant to these two agreements was at a very favorable cost to Oglethorpe. But, more importantly, because Oglethorpe will be selling approximately 24% less energy to its Members, the spreading of Oglethorpe's fixed costs (which remain relatively unchanged) over fewer MWhs sold has the effect of increasing Oglethorpe's average cost of power. It is not unlikely that Oglethorpe's average power cost will increase by approximately 20% or more.

    In October 2004, LEM and its affiliates initiated a binding arbitration process to resolve certain issues relating to the LEM agreement. Oglethorpe expects a decision from the arbitration panel during 2005. Oglethorpe has recorded a $15 million accrual to purchased power energy costs, and a corresponding increase in current liabilities, as a contingent liability to LEM. The $15 million accrual is reflected as an unbilled receivable from the Members on the accompanying balance sheets at December 31, 2004.

Operating Revenues

    Sales to Members.    Oglethorpe's operating revenues fluctuate from period to period based on factors including weather and other seasonal factors, load growth in the service territories of Oglethorpe's Members, operating costs, availability of electric generation resources, Oglethorpe's decisions of whether to dispatch its owned or purchased resources or Member-owned resources over which it has dispatch rights and by Members' decisions of whether to purchase a portion of their hourly energy requirements from Oglethorpe resources or from other suppliers.

    Total revenues from sales to Members increased by 9.6% for 2004 compared to 2003 and increased by 3.6% for 2003 compared to 2002. The components of Member revenues were as follows:

    Capacity revenues from Members increased 2.7% in 2004 compared to 2003 and increased by 2.9% from 2002 to 2003. The increase in capacity revenues in 2004 and 2003 was primarily due to an increase in revenue requirement beginning in May 2003 associated with fixed cost recovery for the Chattahoochee and Talbot generating facilities acquired by Oglethorpe in May 2003. See Note 14 of Notes to Financial Statements for further discussion regarding the merger of Chattahoochee EMC and Talbot EMC into Oglethorpe. For 2003 compared to 2002, these increased fixed costs were mitigated somewhat by lower purchased power capacity costs and by increased depreciation expense in 2002 related to the early retirement of Plant Tallassee. (See "Operating Expenses" below.)

    Energy revenues from Members increased by 17.1% in 2004 compared to 2003 and increased by 4.3% in 2003 compared to 2002. The increase in Member energy revenues in 2004 as compared to 2003 resulted partly from recovery of increases in fuel costs for the Chattahoochee, Talbot and Plant Scherer generating facilities and partly due to increases in purchased power energy costs. The increase in Member energy revenues

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in 2003 was primarily due to recovery of increases in fuel costs related to the Chattahoochee and Talbot generating facilities acquired by Oglethorpe in May 2003. This increase was offset somewhat by lower fuel costs for Doyle. Due to a scheduled outage in 2003, Doyle was utilized less in 2003 than in 2002. (See "Operating Expenses" below.)

    The following table summarizes the amounts of kWh sold to Members and total revenues per kWh during each of the past three years:

    In 2004 and 2003 kWh sales to Members increased 6.9% and 4.5%, respectively. The average revenue per kWh from sales to Members increased 2.5% for 2004 compared to 2003 and decreased 0.9% for 2003 compared to 2002.

    The energy portion of Member revenues per kWh increased 9.5% in 2004 as compared to 2003 and decreased 0.3% in 2003 compared to 2002. Oglethorpe passes through actual energy costs to the Members such that energy revenues equal energy costs. The increase in 2004 of energy revenues per kWh was partly due to the pass-through of higher purchased power costs and partly due to the recovery of increases in fuel costs. (See "Operating Expenses" below.)

    Sales to Non-Members.    Sales to non-Members were from energy sales to power companies and from energy sales to LEM and Morgan Stanley under their power marketer arrangements with Oglethorpe. Total non-Member revenue for 2004 and 2003 were $33,307,000 and $35,948,000, respectively. Oglethorpe sells short-term energy to non-Members for the benefit of Members participating in its capacity and energy pool. Sales to LEM and Morgan Stanley represent the net energy transmitted on behalf of LEM and Morgan Stanley off-system on an hourly basis from Oglethorpe's total resources under the LEM and Morgan Stanley power marketers arrangements. Oglethorpe sold this energy to LEM at Oglethorpe's cost, subject to certain limitations, and to Morgan Stanley at a contractually fixed price. The volume of sales to LEM and Morgan Stanley depends primarily on the power marketers' decisions for servicing their load requirements.

Operating Expenses

    Oglethorpe's operating expenses increased 11.9% in 2004 compared to 2003 and increased 4.3% in 2003 compared to 2002. Operating expenses were higher in 2004 compared to 2003 primarily as a result of increases to fuel costs, purchased power costs, depreciation and amortization expense and accretion expense offset slightly by lower production expenses. The increase in operating expenses in 2003 as compared to 2002 was primarily due to increases in fuel and production expenses.

    Total fuel costs increased 23.9% in 2004 as compared to 2003. The increase in total fuel costs was partly as a result of an increase in MWhs of generation (primarily due to increased MWhs sold to Members) of 9.8% and partly due to higher average fuel costs associated with increased fossil generation and generation output from the Chattahoochee facility, a gas-fired combined cycle plant. For 2004 compared to 2003, output from the coal-fired facilities was 18.7% higher and generation from the Chattahoochee facility was 281,000 MWhs higher. The Chattahoochee facility was acquired in May 2003; therefore, no corresponding fuel costs were incurred and there was no generation output from this facility prior to May 2003. Total fuel costs increased 4.1% in 2003 compared to 2002 primarily as a result of fuel costs incurred at the Chattahoochee and Talbot generating facilities.

    Production expenses decreased 2.2% in 2004 compared to 2003 and increased 9.2% in 2003 compared to 2002. For 2004, production expenses decreased partly due to the reversal of a $1.7 million reserve recorded in 2003 for property taxes related to Plant Vogtle and partly due to $3 million of start-up costs incurred in 2003 related to the Chattahoochee and Talbot generating facilities. There were no such start-up costs incurred in 2004. See Note 12 of Notes to Financial Statements for further discussion regarding ad valorem tax matters. The increase in production expenses for 2003 as compared to 2002 resulted primarily from higher operations and maintenance ("O&M") costs. The higher O&M costs resulted from (1) O&M costs incurred at the Chattahoochee and Talbot generating facilities acquired in May 2003; therefore, there was no corresponding O&M costs for these facilities in 2002, (2) costs incurred during a scheduled outage at Doyle (there was no corresponding outage in 2002) and (3) increased property taxes primarily at Plant Scherer.

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    Purchased power costs increased 12.1% in 2004 compared to 2003 and decreased 0.5% in 2003 compared to 2002 as follows:

    The decrease in purchased power capacity costs for 2003 as compared to 2002 resulted primarily from the expiration of contracts for various power purchase agreements.

    Purchased power energy costs increased 14.3% in 2004 compared to 2003 and increased 4.9% in 2003 compared to 2002. The average cost of purchased power energy per kWh increased 11.4% in 2004 compared to 2003 and increased 4.5% in 2003 compared to 2002. The increase in 2004 as compared to 2003 for average purchased power costs resulted from (1) a $15 million accrual as a contingent liability to LEM, (2) slightly higher prices both in the wholesale electricity markets and for energy purchases made from purchased power agreements and (3) an increased amount of purchased power MWhs. For 2003 as compared to 2002, the increase in average purchased power energy costs was attributable to higher prices in the wholesale electricity markets. The amount of purchased power MWhs increased 2.6% in 2004 compared to 2003 and increased 0.4% in 2003 compared to 2002.

    Purchased power expenses for the years 2002 through 2004 include the cost of capacity and energy purchases under various long-term power purchase agreements. These long-term agreements have, in some cases, take-or-pay minimum energy requirements. For 2002 through 2004, Oglethorpe utilized its energy from these power purchase agreements in excess of the take-or-pay requirements. Oglethorpe's capacity and energy expenses under these agreements amounted to approximately $92 million in 2004, $79 million in 2003 and $101 million in 2002. For a discussion of the power purchase agreements, see Note 9 of Notes to Financial Statements.

    Depreciation and amortization increased 8.4% in 2004 compared to 2003 primarily due to depreciation expense associated with the Chattahoochee and Talbot generating facilities acquired by Oglethorpe in May 2003. In addition, higher amortization associated with leasehold improvements at Scherer Unit No. 2 contributed to the increase. While depreciation and amortization increased only slightly from 2002 to 2003, the increase in depreciation expense in 2003 associated with the Chattahoochee and Talbot generating facilities acquired in May 2003 was compared to increased depreciation expense in 2002 due to $9.2 million in accelerated depreciation to write down Plant Tallassee's net book value and for estimated costs associated with its early retirement. Plant Tallasse was subsequently sold in November 2003 and the purchaser assumed responsibility for asset retirement obligations resulting in a $2.8 million credit to deprecation expense in 2003 to reverse the reserve previously recognized.

    Accretion expense, which Oglethorpe began recording in 2003, represents the change in the asset retirement obligations due to the passage of time. For nuclear decommissioning, Oglethorpe records a regulatory asset for the timing difference in accretion expense recognized under SFAS No. 143 compared to the expense recovered for ratemaking purposes. In 2004 Oglethorpe recovered more accretion expense in its rates compared to the amount of accretion expense recovered in rates for 2003. For a discussion regarding adoption of SFAS No. 143, see Note 1 of Notes to Financial Statements.

Other Income (Expense)

    Investment income increased 44.2% in 2004 compared to 2003. For 2003 compared to 2002 investment income was approximately the same. The increase in 2004 was primarily due to higher earnings from the decommissioning trust fund. Amortization of net benefit of sale of income tax benefit decreased $2 million in 2003 compared to 2002 due to amortization of the safe harbor lease ending in March 2002.

Interest Charges

    Other interest expense decreased 47.9% or $2.6 million in 2004 compared to 2003 and decreased 49.7% or $5.3 million in 2003 compared to 2002. The lower other interest expense in 2004 and 2003 was primarily attributable to commercial paper issued to finance a portion of the Talbot EMC and Chattahoochee EMC construction projects being refinanced with long-term FFB loans and the related interest costs are now reflected in interest on long-term debt and capital leases. Amortization of debt discount and expense increased 15.1% in 2004 compared to 2003 primarily due to amortization of debt issuance costs associated

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with a $133.3 million PCB refunding transaction completed in December 2003.

Net Margin

    Oglethorpe's net margin for 2004, 2003 and 2002 was $17.2 million, $16.8 million and $17.5 million, respectively. Oglethorpe's margin requirement is based on a ratio applied to interest charges. In addition, Oglethorpe's margins include certain items that are excluded from the Margins for Interest Ratio, such as non-cash capital credits allocation from GTC. For 2003, Oglethorpe's non-cash capital credits allocation from GTC was $305,000 and $733,000 lower than the allocations received in 2004 and 2002, respectively. (See "Summary of Cooperative Operations – Rates and Regulations" above.)

Financial Condition

General

    Oglethorpe's 2004 retained net margin of $17 million produced a Margins for Interest Ratio of 1.10, which met the Margins for Interest requirement under the Mortgage Indenture. The retained net margin caused a corresponding increase in patronage capital, bringing total patronage capital to $462 million at December 31, 2004. The patronage capital increase brought Oglethorpe's equity to capitalization ratio to 11.5% at year end.

    Cash and cash equivalents increased by $67 million, primarily due to (1) lower property additions in 2004 than in 2003, and (2) a FFB quarterly debt payment due December 31, 2004 that was paid on the first business day of 2005, whereas the amount due on December 31, 2003 was paid on that day.

    Property additions totaled approximately $66 million and were financed with funds from operations. The expenditures were primarily for purchases of nuclear fuel and additions and replacements to existing generation facilities.

Capital Requirements

    Capital Expenditures.    As part of its ongoing capital planning, Oglethorpe forecasts expenditures required for generating facilities and other capital projects. The table below details these expenditure forecasts for 2005 through 2007. Actual expenditures may vary from the estimates listed below because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, cost of capital, equipment, material and labor, and changing environmental requirements.

⁽¹⁾

Excludes allowance for funds used during construction.

    Oglethorpe may be subject to future environmental regulations, including future implementation of existing laws and regulations. Since alternative legislative and regulatory environmental compliance programs continue to be debated on a national level, it is difficult to predict what capital costs may ultimately be required, even in the near term. Oglethorpe monitors the on-going debate to gauge the possible capital expenditure requirements of various alternatives. While estimates can vary widely, it is not unlikely that Oglethorpe may be required to make additional investments of $150 million or more for the three years beyond the period reflected in the table above.

    Expenditures for environmental compliance will ultimately depend on, among others, the following factors:

•

which of several competing legislative and regulatory programs are implemented;

•

timing of implementation of regulations imposing restrictions;

•

control technologies available at the time restrictions become applicable;

•

costs of applying available control technologies at specific plants;

•

availability of technologies that control multiple emissions;

•

the remaining useful life of a plant at the time an expenditure is made;

•

efficiencies of controlling plants within a specific area;

•

levels of emissions allowances permitted under proposed regulations or rules; and

•

development and liquidity of markets for emissions allowances.

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    Depending on how Oglethorpe and the other co-owners of Plants Scherer and Wansley choose to comply with these regulations, once finalized, both capital expenditures and operating expenditures may be impacted. For example, if it is an option, purchasing emissions allowances would result in greater future operating expenses but would decrease the estimated amount of future capital expenditures. In any event, as required by the Wholesale Power Contracts, Oglethorpe expects to be able to recover from its Members all capital and operating expenditures made in complying with future environmental regulations.

    The most significant environmental legislation applicable to Oglethorpe is the Clean Air Act. The recently finalized regulations and proposed regulations issued pursuant to the Clean Air Act that appear to be the most significant are NAAQs for ozone and fine particulate matter, regional regulation of sulfur dioxide and nitrogen oxides, and control of emissions of mercury. For further discussion of these regulations, see "BUSINESS – ENVIRONMENTAL AND OTHER REGULATION – Clean Air Act."

    Contractual Obligations.    The table below reflects, as of December 31, 2004, Oglethorpe's contractual obligations for the periods indicated.

⁽¹⁾

Includes an interest rate assumption for variable rate debt.

⁽²⁾

Amounts represent total rental payment obligations, not amortization of debt underlying the leases.

⁽³⁾

Oglethorpe entered into a funding agreement with a highly rated entity to fund this obligation. For additional information, see "Off-Balance Sheet Arrangements-Rocky Mountain Lease Arrangements" below.

Off-Balance Sheet Arrangements

    Oglethorpe is liable for certain contractual obligations under which other parties are liable, and Oglethorpe would be expected to pay only if the other parties fail to satisfy such obligations. These obligations are not shown on Oglethorpe's balance sheet and are described below.

    GTC Portion of PCBs and Interest Rate Swaps.    In connection with a corporate restructuring in 1997 in which Oglethorpe sold its transmission related assets to GTC (which represented 16.86% of Oglethorpe's assets), GTC assumed 16.86% of the then outstanding indebtedness associated with PCBs. If GTC fails to satisfy its obligations under this debt, Oglethorpe would then remain liable for any unsatisfied amounts. In that event, Oglethorpe would be entitled to reimbursement from GTC for any amounts paid by Oglethorpe. At December 31, 2004, the total obligation assumed by GTC relating to outstanding PCB principal was $99 million. (See Note 5 of Notes to Financial Statements.) In 2005, GTC's estimated payments of principal and interest pursuant to this assumed obligation will be approximately $7 million.

    Oglethorpe also remains secondarily liable for a 16.86% portion of Oglethorpe's interest rate swaps that were assumed by GTC in connection with the corporate restructuring. GTC's portion of the estimated maximum aggregate liability for termination payments under the swaps had such payments been due on December 31, 2004 would have been $9 million.

    Rocky Mountain Lease Arrangements.    In December 1996 and January 1997, Oglethorpe entered into a total of six lease transactions relating to its 74.61% undivided interest in Rocky Mountain. In each transaction, Oglethorpe leased a portion of its undivided interest in Rocky Mountain to an owner trust for the benefit of an investor for a term equal to 120% of the estimated useful life of Rocky Mountain, in exchange for one-time rental payments aggregating $794 million made at the time the leases were entered into. Each owner trust funded a portion of its payment to Oglethorpe through an equity contribution (in the aggregate totaling $171 million), and financed the remaining portion through a loan from a bank. Immediately following the leases to the owner trusts, the owner trusts leased their undivided interests in Rocky Mountain to a wholly owned Oglethorpe subsidiary, Rocky Mountain Leasing Corporation ("RMLC"), for a term of 30 years under separate leases (the "Facility Leases"). RMLC then subleased the undivided interests back to Oglethorpe for an identical term also under separate leases (the "Facility Subleases").

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    Oglethorpe used a portion of the one-time rental payments paid to it by the owner trusts to acquire the capital stock of RMLC and to make a $698 million capital contribution to RMLC. RMLC in turn used the capital contribution to fund payment undertaking agreements (in the aggregate totaling $641 million) and funding agreements (in the aggregate totaling $57 million) that provide for third parties to pay all of:

•

RMLC's periodic basic rent payments under the Facility Leases; and

•

the fixed purchase price of the undivided interests in Rocky Mountain at the end of the terms of the Facility Leases if Oglethorpe causes RMLC to exercise its option to purchase these interests at that time.

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

    The Facility Subleases require Oglethorpe to make semi-annual rental payments to RMLC. In turn, RMLC is required to make identical rental payments to the owner trusts under the Facility Leases. In 2004, the amount of the rental payments under the Facility Subleases and Facility Leases each totaled $54 million. The payment undertaking agreements require the other party (the "payment undertaker") to pay the rent payments directly to the owner trust's lender in satisfaction of RMLC's rent payment obligation under the Facility Lease and the applicable owner trust's repayment obligation under the loan to it. Because RMLC funds these rent payments through the payment undertaking agreements, RMLC returns to Oglethorpe amounts received by it pursuant to the Facility Subleases. RMLC remains liable for all rental payments under the Facility Leases if the payment undertaker fails to make such payments, although the owner trusts have agreed to use due diligence to pursue the payment undertaker before pursuing payment from RMLC or Oglethorpe.

    The senior unsecured debt obligations of the payment undertaker are rated "AAA" by S&P and "Aaa" by Moody's, and the senior unsecured debt obligations of the third party to the funding agreement are rated "AA+" by S&P and "Aaa" by Moody's.

    As a wholly owned subsidiary of Oglethorpe, the financial condition and results of operations of RMLC are fully consolidated into Oglethorpe's financial statements. The funding agreements and corresponding lease obligations are reflected on the balance sheets of RMLC and Oglethorpe as Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions (both $83 million at December 31, 2004). However, the financial statements of RMLC and Oglethorpe do not reflect the payment undertaking agreements or the corresponding lease obligations, or the payments made by the payment undertaker, including the payments of rent under the Facility Leases and Facility SubLeases, because they have been extinguished for financial reporting purposes. If RMLC's interests in the payment undertaking agreements and the corresponding lease obligations were reflected on the balance sheets of RMLC and Oglethorpe at December 31, 2004, both the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions would have been higher by $714 million.

    At the end of the term of each Facility Lease, Oglethorpe has the option to cause RMLC to purchase any owner trust's undivided interests in Rocky Mountain at fixed purchase option prices that aggregate $1.087 billion for all six Facility Leases. The payment undertaking agreements and funding agreements would fund $715 million and $372 million of this amount, respectively, and these amounts would be paid to the owner trusts over five installments in 2027. If Oglethorpe does not elect to cause RMLC to purchase any owner trust's undivided interest in Rocky Mountain, GPC has an option to purchase that undivided interest. If neither Oglethorpe nor GPC exercises its purchase option, and Oglethorpe returns (through RMLC) any undivided interest in Rocky Mountain to an owner trust, that owner trust has several options it can elect, including:

•

causing RMLC and Oglethorpe to renew the related Facility Leases and Facility Subleases for up to an additional 16 years and provide collateral satisfactory to the owner trusts,

•

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

•

retaining the undivided interest for its own benefit.

    Under the first two of these options Oglethorpe must arrange new financing for the outstanding loans to the

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owner trusts. The aggregate amount of the outstanding loans to all of the owner trusts at the end of the term of the Facility Leases is anticipated to be $666 million. If new financing cannot be arranged, the owner trusts can ultimately cause Oglethorpe to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the debt or cause RMLC to exercise its purchase option or RMLC and Oglethorpe to renew the Facility Leases and Facility Subleases, respectively.

    If option one above is chosen, at the end of the 46-year lease term, the Facility Leases and Facility Subleases terminate, the owner trusts take possession of Rocky Mountain at whatever its value and operating condition may be at such time, with no residual value guaranty.

Liquidity and Sources of Capital

    Sources of Capital.    Oglethorpe has historically obtained the majority of its long-term financing from RUS guaranteed loans funded by FFB. In the future, however, RUS-guaranteed funding for new generation facilities may be limited due to budgetary pressures faced by Congress and evolving RUS policies that may limit loan funds where the proceeds are used in "urban" rather than "rural" areas. Oglethorpe has also obtained a substantial portion of its long-term financing requirements from the issuance of tax-exempt PCBs.

    In addition, Oglethorpe's operations have historically provided a sizable contribution to its funding of capital requirements, such that internally generated funds have provided interim funding or long-term capital for nuclear fuel reloads, general plant facilities, replacements and additions to existing facilities, expenditures for environmental compliance, and retirement of long-term debt. In the future, Oglethorpe anticipates that it will meet these types of capital requirements through a combination of funds generated from operations and short and long-term borrowings. (See "Other Planned Financings" below.)

    At December 31, 2004, Oglethorpe had $561 million of unrestricted available liquidity to meet short-term cash needs and liquidity requirements. This liquidity consisted of (i) $134 million in cash and cash equivalents, (ii) $7 million in other investments, (iii) $20 million available under a letter of credit with the National Rural Utilities Cooperative Finance Corporation ("CFC"), and (iv) up to $400 million available under the following committed line of credit ("LOC") facilities:

    Unrestricted available liquidity decreased from December 31, 2003 to December 31, 2004 primarily due to (1) a reclassification of $58 million invested in auction rate securities from a current asset to a long-term investment, and (2) a reclassification of $81 million from other short term investments to restricted short-term investments relating to the RUS Cushion of Credit Account described below.

    In addition to unrestricted available liquidity, Oglethorpe had $93 million in restricted cash and cash equivalents and restricted short-term investments at December 31, 2004. Of this amount, $12 million relates to amounts on deposit with a trustee relating to PCBs issued in December 2004, the proceeds of which were used to refinance a like amount of PCB principal maturing in January 2005. (See "Refinancing Transactions" below.) The remaining $81 million relates to a RUS Cushion of Credit Account established with the U.S. Treasury in mid-2004 that earns interest at a guaranteed rate of 5% per annum, which is more than Oglethorpe is currently earning on its general funds investments. The funds in the account, including interest earned thereon, can only be applied to future debt service on RUS and RUS-guaranteed FFB notes. As of December 31, 2004, the amount on deposit equals approximately four months of Oglethorpe's RUS/FFB debt service. Based on Oglethorpe's view of interest rates and its operational needs, it is currently estimated that in 2006 the funds in the RUS Cushion of Credit Account will have been fully utilized to pay RUS/FFB debt service.

    Under the commercial paper program Oglethorpe is authorized to issue commercial paper in amounts that do not exceed the amount of its committed backup line of credit, thereby providing 100% dedicated support for any paper outstanding. Oglethorpe periodically assesses its needs to determine the appropriate amount of commercial paper backup to maintain and currently has in place a $300 million committed backup facility

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provided by a group of six banks that was syndicated by Bank of America. In September 2004, the commercial paper backup facility was converted from a 364-day to a three- year facility. Also, a provision was added that provides a mechanism to increase the size of the revolving loan commitment up to $370 million, pending bank approval of the increase at the time of the request. Along with the CoBank and CFC lines of credit, the backup facility supporting the commercial paper may also be used for general working capital needs. However, any amounts drawn under the backup facility for working capital will reduce the amount of commercial paper that Oglethorpe is authorized to issue.

    Liquidity Covenants.    Oglethorpe currently has three financial agreements in place which contain liquidity covenants. These agreements include the two interest rate swaps relating to PCB transactions and the Rocky Mountain lease transactions. The amount of liquidity required under these agreements was $73 million as of December 31, 2004, and Oglethorpe had sufficient liquidity to satisfy these requirements.

Credit Rating Risk

    The table below sets forth Oglethorpe's current debt ratings.

⁽¹⁾

NRA = no rating assigned

⁽²⁾

Moody's also assigns Oglethorpe an "Issuer Rating" of Baa1

    Oglethorpe has financial agreements containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral (in the form of either letters of credit, surety bonds or cash) or termination of the agreement. The table below sets forth the more significant rating triggers contained in Oglethorpe's financial agreements.

⁽¹⁾

NA = rating not included as a trigger in agreement

    Under the interest rate swap arrangements, if Oglethorpe's rating from Standard & Poor's or Moody's falls below the levels shown in the table above, the swap counterparty has the option of (1) making swap payments based on an index rather than the actual variable rate on the bonds, or (2) causing an early termination of the swaps. In the event of a termination, either party could owe the other party a termination payment depending on the market value of the swap position. Oglethorpe estimates that at December 31, 2004, a termination of the swaps would have required Oglethorpe to make a termination payment of approximately $45 million. Except in situations where Oglethorpe voluntarily elects to terminate the interest rate swaps early, Oglethorpe has the right to pay a termination payment due to the swap counterparty over a term of up to five years. The swap arrangements extend for the life of the underlying bonds, which have sinking fund amortization. Therefore, all other things being equal, annual reductions in the outstanding principal amounts will reduce termination payments. For a further discussion of termination events under the swaps, see "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Interest Rate Risk – Interest Rate Swap Transactions."

    Provisions in the Rocky Mountain lease transactions could require Oglethorpe to put up additional surety bonds or letters of credit in the amount of $50 million if Oglethorpe fails to maintain at least two of the three ratings shown in the table above for each of the senior secured and the senior unsecured debt (if any and if rated) or if it fails to maintain at least $50 million in available liquidity.

    Provisions in the RUS Loan Contract and certain PCB loan agreements contain covenants based on credit ratings that could result in increased interest rates or restrictions on issuing debt but would not result in acceleration of any debt.

    Given its current level of ratings, Oglethorpe's management does not believe that the rating triggers contained in any of its financial agreements will have a material adverse effect on its results of operations or financial condition. However, Oglethorpe's ratings reflect the views of the rating agencies and not of Oglethorpe, and therefore Oglethorpe cannot give any assurance that its ratings will be maintained at current levels for any period of time.

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Refinancing Transactions

    Oglethorpe has a program under which it is refinancing, on a continued tax-exempt basis, the annual principal maturities of serial bonds and the annual sinking fund payments of term bonds originally issued on behalf of Oglethorpe by various county development authorities. The refinancing of these PCB principal maturities allows Oglethorpe to preserve a low-cost source of financing. To date, Oglethorpe has refinanced approximately $209 million under this program, including $12 million of PCB principal that matured on January 1, 2005. Oglethorpe has Board approval to refinance an additional $37 million of PCB principal that matures in 2006 and 2007.

    Under an indemnity agreement executed in connection with GTC's assumption of PCB indebtedness in the 1997 corporate restructuring, GTC is entitled to participate in any refinancing of this PCB debt by Oglethorpe by agreeing to assume a portion of the refinancing debt. However, to-date GTC has agreed not to participate in Oglethorpe's refinancing of the PCB principal maturities. Pursuant to this agreement, Oglethorpe provided a discount of $583,000 and received cash of $1.4 million on the $1.9 million due from GTC in connection with the $12 million refinancing discussed above. GTC is currently evaluating its options with respect to the possible refinancings of PCB principal maturing in 2006 and 2007.

    The average interest rate on long-term debt and capital lease obligations was 5.25% at December 31, 2004.

Other Planned Financings

    Oglethorpe submitted a loan application totaling $72 million to the RUS in September 2004, and anticipates that RUS will take action on it by mid-year 2005. If approved, the loan will fund normal additions and replacements to generation facilities incurred in 2004 and expected to be incurred in 2005 through 2007.

    In the second half of 2005, Oglethorpe anticipates submitting another loan application to the RUS totaling approximately $100 million or more to fund capital expenditures forecasted to be made in complying with environmental regulations. Oglethorpe does not expect RUS to act on this loan request until 2006.

    If approved, both of these loans would be funded through the FFB and guaranteed by the RUS, and the debt would be secured under Oglethorpe's Mortgage Indenture.

Inflation

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

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

       Due to its cost-based rate structure, Oglethorpe has limited exposure to market risks. However, changes in interest rates, equity prices, and commodity prices may result in fluctuations in Member rates. Oglethorpe uses derivatives only to manage this volatility and does not use derivatives for speculative purposes. (See "BUSINESS – OGLETHORPE POWER CORPORATION – Electric Rates" for further discussion on Oglethorpe's rate structure.)

    Oglethorpe's Risk Management Committee ("RMC") provides general oversight over all risk management activities, including commodity trading, fuels management, insurance procurement, debt management and investment portfolio management. The RMC is comprised of senior executive officers, including the Chief Executive Officer, the Chief Operating Officer, the Chief Financial Officer and the Senior Vice President, Administration and Risk Management. The RMC has implemented comprehensive risk management policies to manage and monitor credit and market price risks. These policies also specify controls and authorization levels related to various risk management activities. The RMC frequently meets to review corporate exposures, risk management strategies, and hedge positions. The RMC regularly reports corporate exposures and risk management activities to the Audit Committee of the Board of Directors.

Interest Rate Risk

    Oglethorpe is exposed to the risk of changes in interest rates due to the significant amount of financing obligations it has entered into, including variable rate debt and interest rate swap transactions. Oglethorpe's objective in managing interest rate risk is to maintain a balance of fixed and variable rate debt that will lower its overall borrowing costs within reasonable risk parameters. As part of this debt management strategy, Oglethorpe has a guideline of having between 15% and 30% variable rate debt to total debt. At December 31, 2004, Oglethorpe had 19% of its debt (including capital lease debt) in a variable rate mode.

    The table below details Oglethorpe's existing debt instruments and provides the fair value at December 31, 2004, the outstanding balance at the beginning and end of each year and the annual principal maturities and associated average interest rates.

⁽¹⁾

99% of the variable rate debt outstanding at 1/1/05 related to PCB debt with bullet maturities beyond 2009, with a weighted average interest rate of 1.7%. Future variable debt interest rates are adjusted based on a forward BMA yield curve.

⁽²⁾

Debt underlying the interest rate swaps is variable rate PCB debt that was swapped to a contractual fixed rate of interest in 1993, so the average interest rate on maturing debt represents the average of the two contractual fixed rates.

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    Substantially all of the variable rate debt in the above table is comprised of variable rate PCB debt, which had a weighted average interest rate at January 1, 2005 of 1.7%. If interest rates on this debt increased 100 basis points, interest expense would increase by approximately $5.8 million on an annualized basis. The operative documents underlying this debt contain provisions that allow Oglethorpe to convert the debt to a variety of variable interest rate modes (such as daily, weekly, monthly or commercial paper mode), or to convert the debt to a fixed rate of interest to maturity. This optionality improves Oglethorpe's ability to manage its exposure to variable interest rates.

    At any point in time, Oglethorpe may analyze and consider using various types of derivative products (including swaps, caps, floors and collars) to help manage its interest rate risk. Currently, however, Oglethorpe's use of interest rate derivatives is limited to the two substantially identical swap transactions described below, which are considered "plain vanilla" by industry standards.

Interest Rate Swap Transactions

    Oglethorpe has two interest rate swap transactions with a swap counterparty, AIG Financial Products Corp. ("AIG-FP"), which were designed to create a contractual fixed rate of interest on $322 million of variable rate PCBs. These transactions were entered into in early 1993 on a forward basis, pursuant to which approximately $200 million of variable rate PCBs were issued on November 30, 1993 (the 1993 bonds) and approximately $122 million of variable rate PCBs were issued on December 1, 1994 (the 1994 bonds). Oglethorpe is obligated to pay the variable interest rate that accrues on these PCBs; however, the swap arrangements provide a mechanism for Oglethorpe to achieve a contractual fixed rate which is lower than Oglethorpe would have obtained had it issued fixed rate bonds at that time. In connection with GTC's assumption of liability on a portion of the PCBs pursuant to the corporate restructuring by which GTC became a separate company, commencing April 1, 1997, GTC assumed and agreed to pay 16.86% of any amounts due from Oglethorpe under these swap arrangements, including the net swap payments and potential termination payments described below. Should GTC fail to make such payments, Oglethorpe remains obligated for the full amount of such payments.

    Under the swap arrangements, Oglethorpe is obligated to make periodic payments to AIG-FP based on a notional principal amount equal to the aggregate principal amount of the bonds outstanding during the period and a contractual fixed rate ("Fixed Rate"), and AIG-FP is obligated to make periodic payments to Oglethorpe based on a notional principal amount equal to the aggregate principal amount of the bonds outstanding during the period and a variable rate equal to the variable rate of interest accruing on the bonds during the period ("Variable Rate"). These payment obligations are netted, such that if the Variable Rate is less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if the Variable Rate is higher than the Fixed Rate, Oglethorpe receives a net payment from AIG-FP. Thus, although changes in the Variable Rate affect whether Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive payments from AIG-FP, the effective interest rate Oglethorpe pays with respect to the PCBs is not affected by changes in interest rates. The Fixed Rate on the 1993 bonds is 5.67% and the Fixed Rate on the 1994 bonds is 6.01%. At December 31, 2004, there was $180 million notional amount outstanding of 1993 bonds (carrying a variable rate of interest of 1.99%) and $110 million notional amount outstanding of 1994 bonds (carrying a variable rate of interest of 2.00%). For the three years ended December 31, 2002, 2003 and 2004, Oglethorpe has made in connection with both interest rate swap arrangements combined net swap payments to AIG-FP (net of amounts assumed by GTC) of $11.2 million, $11.8 million and $11.0 million, respectively.

    The obligation of AIG-FP to make payments to Oglethorpe under the swap arrangements are guaranteed by AIG-FP's parent company, American International Group, Inc. ("AIG"). The senior unsecured debt obligations of AIG and AIG-FP are rated "AA+" and "Aaa" by Standard and Poor's and Moody's, respectively.

    Unless terminated, the swap arrangements will extend for the life of the underlying PCBs (through January 2016 and January 2019 for the 1993 bonds and 1994 bonds, respectively). AIG-FP has limited rights to terminate the swaps only upon the occurrence of specified events of default or due to an Oglethorpe

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Downgrading. Termination Events related to rating downgrades are as follows:

•

Oglethorpe Downgrading (defined as uncredit-enhanced ratings below "BBB-" or "Baa3" on Oglethorpe's secured PCBs);

•

Guarantor Downgrading (defined as AIG ratings below "A-" or "A3"); and

•

Bond Downgrading (defined as ratings on the underlying bonds below "AA-" or "Aa3"; the bonds are insured by a triple-A municipal bond insurer and therefore carry the same rating).

Based on the current ratings of the parties to the swap transactions, Oglethorpe views its counterparty credit risk as insignificant and a termination from a downgrade event as an unlikely occurrence.

    If the swap arrangements were to be terminated while the PCBs are still outstanding, Oglethorpe or AIG-FP may owe the other party a termination payment depending on a number of factors, including whether the fixed rate then being offered under comparable swap arrangements is higher or lower than the Fixed Rate. Oglethorpe estimates that its maximum aggregate liability (net of GTC's assumed percentage) for termination payments under both swap arrangements had such payments been due on December 31, 2004 would have been $45 million. Except in situations where Oglethorpe voluntarily elects to terminate the interest rate swaps early, Oglethorpe has the right to a term-out of any termination payment due to the swap counterparty for a term of up to five years.

Capital Leases

    In December 1985, Oglethorpe sold and subsequently leased back from four purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The capital leases provide that Oglethorpe's rental payments vary to the extent of interest rate changes associated with the debt used by the lessors to finance their purchase of undivided ownership shares in the unit. The debt currently consists of $136 million in serial facility bonds due June 30, 2011 with a 6.97% fixed rate of interest.

    Oglethorpe entered into a power purchase and sale agreement with Doyle I, LLC to purchase all of the output from a five-unit gas-fired generation facility. The Doyle agreement is reported on Oglethorpe's balance sheet as a capital lease. The lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00%. At December 31, 2004, the weighted average interest rate on the lease obligation was 6.61%.

Equity Price Risk

    Oglethorpe maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning. (See Note 1 of Notes to Financial Statements.) As of December 31, 2004, these funds were invested in U.S. Government securities, domestic and international equities and global fixed income securities. By maintaining a portfolio that includes long-term equity investments, Oglethorpe intends to maximize the returns to be utilized to fund nuclear decommissioning, which in the long-term will better correlate to inflationary increases in decommissioning costs. However, the equity securities included in Oglethorpe's portfolio are exposed to price fluctuation in equity markets. A 10% decline in the value of the fund's equity securities as of December 31, 2004 would result in a loss of value to the fund of approximately $8 million. Oglethorpe actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets in its trusts to various investment options. Because realized and unrealized gains and losses from investment securities held in the decommissioning fund are directly added to or deducted from the decommissioning reserve, fluctuations in equity prices do not affect Oglethorpe's net margin in the short-term.

Commodity Price Risk

Coal

    Oglethorpe is also exposed to the risk of changing prices for fuels, including coal and natural gas. Oglethorpe has interests in 1,501 MW of coal-fired capacity (Plants Scherer and Wansley). Oglethorpe purchases coal under term contracts and in spot-market transactions. Oglethorpe's coal contracts provide volume flexibility and fixed prices. Oglethorpe anticipates that its existing contracts will provide fixed prices for all of its forecasted coal requirements in 2005. Additionally, such contracts will provide about 89% of Oglethorpe's coal requirements in 2006 and 68% of its 2007 coal requirements. The objective of Oglethorpe's coal procurement strategy is to ensure reliable coal supply and some price stability for the Members. Its strategy focuses on hedging requirements over a three-year time horizon, but permits opportunities to make purchases up

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to six years into the future. The procurement guidelines provide for layering in fixed prices by annually entering into forward contracts for between 25% and 35% of the forecasted requirements, for a rolling three-year period.

Natural Gas

    Oglethorpe owns two gas-fired generation facilities totaling 1,086 MW of capacity. (See "PROPERTIES – Generating Facilities.")

    Oglethorpe also has power purchase contracts with Doyle I, LLC (which Oglethorpe treats as a capital lease) and Hartwell Energy Limited Partnership under which approximately 625 MW of capacity and associated energy is supplied by gas-fired facilities. (See "BUSINESS – OGLETHORPE'S POWER SUPPLY RESOURCES – Power Purchase and Sale Arrangements – Power Purchases" and "PROPERTIES – Generating Facilities.") Under these contracts, Oglethorpe is exposed to variable energy charges, which incorporate each facility's actual operation and maintenance and fuel costs. Oglethorpe has the right to purchase natural gas for Doyle and the Hartwell facility and exercises this right from time to time to actively manage the cost of energy supplied from these contracts and the underlying natural gas price and operational risks.

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

    Oglethorpe has entered into natural gas swap arrangements to manage its exposure to fluctuations in the market price of natural gas. Under these swap agreements, Oglethorpe pays the counterparty a fixed price for specified natural gas quantities and receives a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, Oglethorpe will make a net payment, and if the market price index is higher than the fixed price, Oglethorpe will receive a net payment. If the natural gas swaps had been terminated at December 31, 2004, Oglethorpe would have made a net payment of approximately $136,000.

    Oglethorpe has obtained the Members' approval required by the New Business Model Member Agreement to continue to manage exposures to natural gas price risks for Members that elect to receive such services. Oglethorpe is providing natural gas price risk management services to 13 of its Members. At the beginning of each calendar year, additional Members may elect to receive these services. Members may elect to discontinue receiving these services at any time.

Changes in Risk Exposure

    Oglethorpe's exposure to changes in interest rates, the price of equity securities it holds, and commodity prices have not changed materially from the previous reporting period. Oglethorpe is not aware of any facts or circumstances that would significantly impact these exposures in the near future; however, nonperformance by one of Oglethorpe's hedge counterparties may increase its exposure to market volatility.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index To Financial Statements

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STATEMENTS OF REVENUES AND EXPENSES

For the years ended December 31, 2004, 2003 and 2002