On December 30, 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. 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.

               On January 16, 2003, the Sierra Club appealed an unsuccessful challenge to an air operating permit for the combined cycle facility then owned by Chattahoochee EMC to the United States Court of Appeals for the Eleventh Circuit. Oglethorpe acquired this facility in the second quarter of 2003. (See “Oglethorpe Power Corporation—Power Supply Business.”) Oglethorpe has intervened in the appeal. The petitioner seeks to have the air permit invalidated and remanded back to EPA and EPD. Although Oglethorpe believes that a favorable outcome in this appeal is likely, an unfavorable ruling could temporarily affect the ability of the facility to continue to operate.

               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. The power marketer arrangements generally do not provide for the recovery from the power marketers of increased environmental costs. (See “Oglethorpe’s Power Supply Resources—Power Marketer Arrangements.”) Because of the uncertainty associated with these various developments, Oglethorpe cannot now predict the effect that any of these potential requirements may have on the operations of Plants Wansley and Scherer.

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               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.”)

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 2005, substantial additional costs for the management of these wastes might be required of Oglethorpe.

               Under the Clean Water Act, EPA has developed new rules intended to reduce the impingement and entrainment of fish and fish larvae at cooling water intake structures. Those rules will require numerous biological studies and perhaps retrofits to some intake structures at existing power plants. The new rule was finalized on February 16, 2004 and its impacts on Plants Scherer and Wansley are currently being evaluated.

               Also 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.

               The scientific community, regulatory agencies and the electric utility industry are continuing to examine the issues of global warming and the possible health effects of electromagnetic fields. While no definitive scientific conclusions have been reached, it is possible that new laws or regulations pertaining to these matters could increase the capital and operating costs of electric utilities, including Oglethorpe or entities from which Oglethorpe purchases power. In addition, the potential for liability exists from lawsuits that might be brought alleging damages from electromagnetic fields. Oglethorpe, or generating facilities in which Oglethorpe has an interest, are also subject, from time to time, to claims relating to emissions of pollutants, including actions by citizens to enforce environmental regulations and claims for personal injury due to emissi ons from the facilities. 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 the financial position or results of operations of Oglethorpe.

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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 subjec t to revocation, suspension or modification, and 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.

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Plant Performance

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

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

Fuel Supply

               Coal. Coal for Plant Wansley is currently purchased under term contracts and in spot market transactions. As of February 29, 2004, there was a 66-day coal supply at Plant Wansley based on nameplate rating.

               Coal for Scherer Units No. 1 and No. 2 is purchased under term contracts and in spot market transactions. As of February 29, 2004, the coal stockpile at Plant Scherer contained a 39-day supply based on nameplate rating. The co-owners of Plant Scherer recently completed a project to convert Units No. 1 and No. 2 at Plant Scherer to burn sub-bituminous coal. Oglethorpe currently leases 1,220 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 l may have on Oglethorpe, see “Environmental and Other Regulations—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 to operate these plants, including nuclear fuel procurement. Southern Nuclear Operating Company (“SONOPCO”) 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.

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               Natural Gas. Oglethorpe purchases the natural gas, including transportation and other related services, needed to operate Plant 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 participate in Oglethorpe’s pool or elect to receive such services. Oglethorpe purchases transportation under long-term firm and short-term firm and non-firm contracts. (See “Qualitative and Quantitave Disclosures About Market Risk—Commodity Price Risk.”)

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.

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               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 “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.

               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 entered into power sales contracts with each of 48 cities and one county in the State of Georgia. Such political subdivisions, located in 39 of the State’s 159 counties, collectively serve approximately 290,000 electric consumers (meters).

               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

               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 O wnership 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 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 (the “Sale and Leaseback Transaction”). 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 t he 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.

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               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 SONOPCO as the operator of Plants Hatch and Vogtle, pursuant to the Nuclear Operating Agreement between GPC and SONOPCO, 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 coordin ate 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 GPC and to su bstitute 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 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, fo llowing 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.

               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.

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               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 s uspended 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  7;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 each month a capacity charge based on 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 operates the facility. Doyle I 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.)

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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

               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, 2003, have been derived from the audited financial statements of Oglethorpe. These 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 Power Corporation (“Oglethorpe”), (ii) Oglethorpe’s and the future power supply requirements, resources and arrangements, (iii) Oglethorpe’s expected future capital expenditures and (iv) disclosures regarding market risk included in Item 7A. 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 b eyond 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, “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 the Members 39 retail electric distribution cooperative members (the “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 manag ed throughout the year to ensure that sufficient capacity-related revenues are produced. This rate structure providesOglethorpe 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 2003 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.

               With the ever-increasing importance and scrutiny placed on liquidity, Oglethorpe took steps in 2003 to strengthen its liquidity position by further diversifying its sources of liquidity. While cash balances are a very important source of liquidity for Oglethorpe, cash is not always the least cost means of maintaining liquidity. Accordingly, Oglethorpe developed a more diversified, cost-effective approach to liquidity that contemplates maintaining appropriate levels of cash (including short-term investments), committed lines of credit and a commercial paper program. This resulted in $605 million of available liquidity at year-end.

               Oglethorpe completed a substantial construction program in 2003 with the commencement of commercial operation for the Chattahoochee combined cycle generating facility and the last two units of the six-unit combustion turbine Talbot generating facility. Long-term financing for the two facilities was obtained in May 2003 through loans guaranteed by the Rural Utilities Service (“RUS”) and funded by the Federal Financing Bank (“FFB”). The loan advances, totaling approximately $565 million at year-end, are fixed to maturity at an average interest rate of four percent.

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               Simultaneously with the RUS loan closings, Oglethorpe also 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 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 must plan and implement power supply options to replace a portion of the energy currently being provided by two significant power marketer agreements that will terminate over the next twelve months. While Oglethorpe resources (generating facilities and power purchase contracts) currently provide more than 90% of the Members’ requirements, when the LEM agreement terminates at the end of 2004 and the Morgan Stanley agreement terminates at the end of Ma rch 2005, Oglethorpe resources will only provide approximately 70% of the Members’ requirements.

               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 couple of 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 dramatically, it is not unlikely that Oglethorpe may be required to make significant addit ional investments 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—help 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 help reduce risks associated with coal. Oglethorpe also continues to pursue options to assist with the management of natural gas, including firm transportation capacity and storage alternatives. Oglethorpe will maintain a high degree of focus on fuel strategies as the cost of fuel, higher orlower, translates directly into 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 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 o perations risk, both units of each facility continue an excellent record of operations with availability and capacity factors exceeding 90% in 2003.

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               Despite the 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. Two of Oglethorpe’s strengths, its enterprise-wide risk management program and its system of internal controls, will continue to be enhanced in 2004 as Oglethorpe proceeds with its implementation of the provisions of the Sarbanes-Oxley Act. It is expected that Oglethorpe will spend most of 2004 fine-tuning its operations and processes to further improve efficiency and effectiveness, thereby increasing the value that Oglethorpe provides to the Members.

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, excluding accumulated other comprehensive loss, of $444 million in patronage capital as of December 31, 2003. Oglethorpe’s equity ratio, calc ulated as patronage capital and membership fees divided by total capitalization, decreased from 11.7% at December 31, 2002 to 10.5% at December 31, 2003. The decrease in Oglethorpe’s equity ratio resulted from the increase in debt associated with the merger of Talbot EMC and Chattahoochee EMC into Oglethorpe.

               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 Indenture, dated as of March 1, 1997, from Oglethorpe to SunTrust Bank, as trustee (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 a ggregate 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 Amended and Restated Wholesale Power Contracts (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.

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               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, 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 distribut ion 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 2003, 2002 and 2001, 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 the Georgia Public Service Commission (the “GPSC”).

Accounting Policies

               Basis of Accounting

               Oglethorpe follows generally accepted accounting principles and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission (“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, 2003, Oglethorpe’s regulatory assets and liabilities totaled $270 million and $161 million, respectively. See Note 1 of Notes to Financial Statements. In the event that competitive or other factors make it not probable that Oglethorpe will recover these costs from its Members as future revenues through rates under its Wholesale Power Contracts, Oglethorpe could no longer apply the provisions of SFAS No. 71, which would require Oglethorpe to eliminate all regulatory asse ts and liabilities that could not otherwise be recognized as assets and liabilities by 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.

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               New Accounting Pronouncements

               In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities.” This statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts and for hedging activities under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities.” This statement is effective for contracts entered into or modified after June 30, 2003. This statement does not have a material impact on Oglethorpe’s financial statements.

               In June 2003, the FASB cleared the guidance contained in Derivative Implementation Group (“DIG”) Issue C20, “Scope Exceptions: Interpretation of the Meaning of ‘Not Clearly and Closely Related’ in Paragraph 10(b) regarding Contracts with a Price Adjustment Feature.” DIG Issue C20, which applies only to guidance in paragraph 10(b) of SFAS No. 133, describes three circumstances in which an underlying price adjustment incorporated into a contract that otherwise satisfies the requirements for the normal purchases and normal sales exception would be considered to be “not clearly and closely related to the asset being sold or purchased.” DIG Issue C20 goes into effect for Oglethorpe on November 1, 2003. This statement has no impact on Oglethorpe’s financial statements.

               In May 2003, the FASB issued SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity.” This statement establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within its scope as a liability. This statement requires an issuer to classify as a liability a financial instrument classified as equity that embodies an unconditional obligation that the issuer must redeem the instrument by transferring assets at a specified or determinable date or upon an event certain to occur. A financial instrument that embodies a conditional obligation to redeem the instrument by transferring assets upon an event not certain to occur becomes mandatorily redee mable if that event occurs or the event becomes certain to occur. The return of Oglethorpe’s patronage capital is a conditional obligation because Oglethorpe’s Mortgage Indenture prohibits any return of patronage capital unless Oglethorpe reaches an equity to capitalization ratio significantly higher than its current ratio and because Oglethorpe’s Board of Directors has discretion even then whether to make any distributions of patronage capital. SFAS No. 150 is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective for Oglethorpe beginning January 1, 2004. This pronouncement has no impact on Oglethorpe’s financial statements.

               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 not currently effective for Oglethorpe until the end of fiscal year 2004. However, based on its current analysis, Oglethorpe believes that Interpretation No. 46 will have no impact on its financial statements.

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               Proposed Accounting Pronouncements

The Accounting Standards Executive Committee has issued a proposed Statement of Position (“SOP”), “Accounting for Certain Costs and Activities Related to Property, Plant and Equipment.” The proposed SOP was issued in response to the diversity in accounting for expenditures related to property, plant and equipment (“PP&E”), including improvements, replacements, additions, repairs and maintenance. The proposed SOP addresses the accounting and disclosure issues related to determining which costs related to PP&E should be capitalized and which should be charged to expense as incurred. The proposed SOP also addresses capitalization of indirect costs and component accounting for PP&E. It is uncertain at this time when a final SOP will be issued. If the proposed SOP results in a material difference in the timing of cost recognition from that for ratemaking purposes, Oglethorpe may record an offsetting regulator y asset or liability by implementing the provisions of SFAS No. 71. Oglethorpe’s management is monitoring the developments of the proposed SOP and is assessing the impact this statement may have on its financial statements.

               Oglethorpe currently accounts for nuclear refueling outage costs on a normalized basis and defers and subsequently amortizes to expense the costs over an eighteen month operating cycle. This method is consistent with other companies owning nuclear generating facilities.

               Should the proposed SOP, “Accounting for Certain Costs and Activities Related to Property, Plant, and Equipment” be adopted in its current form, Oglethorpe believes that it would be appropriate to classify outage costs as a regulatory asset under the provisions of SFAS No. 71, rather than a deferred asset. The amortization period for the regulatory asset would be eighteen months. Therefore, Oglethorpe does not believe that the proposed SOP would have any significant impact on the accounting for nuclear costs.

Results of Operations

               Power Marketer Arrangements

               Oglethorpe is utilizing power marketer arrangements to reduce the cost of power to the Members. Oglethorpe has a power marketer agreement with LG&E Energy Marketing Inc. (“LEM”), for approximately 50% of the load requirements of 37 of the Members and an additional power marketer agreement with Morgan Stanley Capital Group Inc. (“Morgan Stanley”), effective May 1, 1997, with respect to 50% of the 39 Members’ then forecasted load requirements. The LEM agreement is based on the actual requirements of the participating Members during the contract term, whereas the Morgan Stanley agreement represents a fixed supply obligation. Generally, these arrangements benefit the Members by limiting the risk of unit availability and by providing future power needs at a fixed price. Most of Oglethorpe’s generating facilities and power p urchase arrangements are available for use by LEM and Morgan Stanley. Oglethorpe continues to be responsible for all of the costs of its system resources but receives revenue from LEM and Morgan Stanley for the use of the resources. After taking into account the Oglethorpe resources made available to LEM and Morgan Stanley for their use, Oglethorpe estimates that about 30%of its power supply capability in 2004 will be provided by these contracts.

               The LEM agreement will terminate as of December 31, 2004. The Morgan Stanley agreement ends on March 31, 2005, but the purchases of certain Members decline to zero prior to that date.

               In February 2001, LEM and its affiliates initiated a binding arbitration process to resolve certain issues relating to the interpretation and administration of the LEM agreement and a similar agreement with Oglethorpe that expired by its terms in 1999. In April 2002, Oglethorpe and LEM settled this arbitration. As part of the settlement, Oglethorpe paid LEM approximately $48,500,000. Oglethorpe recorded a reserve of $36,000,000 in 2001 and an additional expense of $12,500,000 in 2002.

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               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 39 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 3.6% for 2003 compared to 2002 and increased by 4.4% for 2002 compared to 2001. The components of Member revenues were as follows:

               Capacity revenues from Members increased 2.9% in 2003 compared to 2002 and increased by 10.3% from 2001 to 2002. The increase in capacity revenues in 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. These increased fixed costs were offset somewhat by lower purchased power capacity costs. (See “Operating Expenses” below.) The increase in capacity revenues in 2002 was primarily a result of a one-time credit to income tax expense in 2001. (See “Operating Expenses” below.)

               Energy revenues from Members increased by 4.3% from 2002 to 2003 and decreased by 1.5% from 2001 to 2002. The increase in Member energy revenues in 2003 was primarily due to recovery of increases in fuel costs related to the recently acquired Chattahoochee and Talbot generating facilities. (See “Operating Expenses” below.) The decrease in Member energy revenues in 2002 was primarily due to higher purchased power costs in 2001 related to a one-time accrual for estimated damages payable to LEM resulting from the arbitration ruling.

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

               In 2003 and 2002 kWh sales to Members increased 4.5% and 3.6%, respectively. The average revenue per kWh from sales to Members decreased 0.9% for 2003 compared to 2002 and increased 0.7% for 2002 compared to 2001.

               The energy portion of Member revenues per kWh was approximately the same in 2003 as 2002 and decreased 4.9% in 2002 compared to 2001. Oglethorpe passes through actual energy costs to the Members such that energy revenues equal energy costs. The decrease in 2002 of energy revenues per kWh was primarily due to the pass-through of lower purchased power costs. (See “Operating Expenses” below.)

               Sales to Non-Members. The following table summarizes non-Member revenues for the past three years:

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               Sales to power companies represent sales made directly by Oglethorpe. Oglethorpe sells for its own account any energy available from the portion of its resources dedicated to Morgan Stanley that is not scheduled by Morgan Stanley pursuant to its power marketer arrangements. Fewer of the Members participated in the capacity and energy pool in 2002 than in 2001, resulting in less energy being sold by Oglethorpe directly to non-Members.

               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 marketer 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 power marketers depends primarily on the power marketers’ decisions for servicing their load requirements.

               Operating Expenses

               Oglethorpe’s operating expenses increased 4.3% in 2003 compared to 2002 and increased 3.3% in 2002 compared to 2001. Operating expenses were higher in 2003 compared to 2002 primarily as a result of increase to fuel and production expenses. The increased operating expenses in 2002 resulted primarily from higher production expenses and depreciation and amortization costs offset somewhat by lower purchased power costs. In addition, operating expenses in 2001 included a credit to income tax expense.

               Production expenses increased 9.2% in 2003 compared to 2002 and increased 6.3% in 2002 compared to 2001. 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 Plant Doyle (there was no corresponding outage in 2002) and (3) increased property taxes primarily at Plant Scherer. See Note 12 of Notes to Financial Statements for further discussion regarding ad valorem tax matters. The higher production expenses for 2002 as compared to 2001 resulted primarily from higher O&M costs. The higher O&am p;M costs resulted from (1) a forced outage and diesel generator repairs at Plant Hatch, (2) increased security costs at Plants Vogtle and Hatch related to the events of September 11, 2001, (3) one-time costs incurred due to the Southern Nuclear Operating Company engineering reorganization efforts and (4) forced outages at Plants Scherer and Wansley.

               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. Purchased power costs increased 0.5% in 2003 compared to 2002 and decreased 13.7% in 2002 compared to 2001 as follows:

               The decrease in purchased power capacity costs for the period 2001 through 2003 resulted primarily from the expiration of contracts for various power purchase agreements.

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               Purchased power energy costs increased 4.9% in 2003 compared to 2002 and decreased 13.1% in 2002 compared to 2001. The average cost of purchased power energy per kWh increased 4.5% in 2003 compared to 2002 and decreased 8.3% in 2002 compared to 2001. The increase in average purchased power energy costs was attributable to higher prices in the wholesale electricity markets. The decrease in average purchased power energy costs in 2002 was primarily due to a one-time accrual in 2001 for estimated amounts payable to LEM resulting from settlement of an arbitration proceeding regarding the LEM power marketing arrangement. The volumes of purchased power increased 0.4% in 2003 compared to 2002 and decreased 5.3% in 2002 compared to 2001.

               Purchased power expenses for the years 2001 through 2003 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 2001 through 2003, 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 $79 million in 2003, $101 million in 2002 and $130 million in 2001. For a discussion of the power purchase agreements, see Note 9 of Notes to Financial Statements.

               Depreciation and amortization increased 4.7% in 2002 compared to 2001 primarily due to $9.2 million in accelerated depreciation to write down Plant Tallassee’s net book value and for estimated costs associated with early retirement. In November 2003, Oglethorpe completed the sale of Plant Tallassee. The purchaser assumed responsibility for any asset retirement obligations associated with Plant Tallassee, thus Oglethorpe reversed the reserve previously recognized and recorded a credit to expense of approximately $2.8 million in 2003.

               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. For a discussion regarding adoption of SFAS No. 143, see Note 1 of Notes to Financial Statements.

               The credit to income tax expense in 2001 resulted from a change in Oglethorpe’s Bylaws, effective January 1, 2002, to allocate as patronage its patronage-sourced income as computed for Federal income tax purposes rather than its book net margin, which historically had been allocated as patronage. In addition, recent legal developments have clarified the scope of what constitutes patronage-sourced income. Based on these legal developments, Oglethorpe, after consultation with its tax advisors, believes that the sale of power to non-members constitutes patronage-sourced income. Consequently, Oglethorpe anticipates that all temporary differences, including those relating to non-member power sales, that reverse in the future will give rise to patronage-sourced income that will be offset by a patronage dividends deduction. Accordingly, as of December 31, 200 1, Oglethorpe reversed $63,485,000 of net deferred tax liabilities and recognized an income tax credit in the same amount. (See Note 3 of Notes to Financial Statements.)

               Although Oglethorpe believes that its treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment were not sustained, Oglethorpe believes that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on its financial condition or results of operation. See “Results of Operations—Operating Revenues—Sales to Non-Members” below.)

               Other Income (Expense)

               Investment income was approximately the same amount in 2003 as 2002 and decreased 25.9% in 2002 compared to 2001. The decrease in 2002 was partly due to lower cash and temporary cash investments balances and partly due to lower interest earnings on these investments. Amortization of net benefit of sale of income tax benefits decreased $6 million in 2002 compared to 2001 due to the amortization of the safe harbor lease ending in March 2002. (See Note 1 of Notes to Financial Statements.)

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               Interest Charges

               Interest on long-term debt and capital leases was approximately the same amount in 2003 as 2002 and decreased 6.9% in 2002 compared to 2001 primarily as a result of cost savings from lower variable interest rates on long-term debt. Other interest expense decreased 49.7% or $5.3 million in 2003 compared to 2002. The lower other interest expense in 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 decreased 26.5% in 2002 compared to 2001 primarily due to accelerated amortization of $7 million and $24 million in premiums paid to the FFB for refinancing $89 million and $424 million of mortgage notes payable in 1999 and 1998, respectively. Such amortization ended in the third and fourth quarters of 2001, respectively.

               Net Margin

               Oglethorpe’s net margin for 2003, 2002 and 2001 was $16.8 million, $17.5 million and $18.4 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 Georgia Transmission Corporation (“GTC”). For 2003, Oglethorpe’s non-cash capital credits allocation from GTC was $733,000 lower than the allocation received in 2002. For 2002 compared to 2001, the reduction in interest charges reduced Oglethorpe’s margin requirement. (See “Summary of Cooperative Operations—Rates and Regulations” above.)

Financial Condition

               General

               The principal changes in Oglethorpe’s financial condition from December 31, 2002 to December 31, 2003 include the following:

               The increase in electric plant-in-service and long-term debt and the decrease in commercial paper all relate to the acquisition in May 2003 of Chattahoochee EMC and Talbot EMC and the associated financing for this transaction. Electric plant-in-service increased by $571 million, long-term debt increased by $565 million, and outstanding commercial paper decreased by $298 million. (See “Capital Requirements—Financing for Acquisition of Talbot EMC and Chattahoochee EMC” below.)

               Property additions totaled $165 million and approximately $124 million of this amount was financed with funds from operations. The expenditures were primarily for compliance with environmental regulations ($52 million), purchases of nuclear fuel ($48 million), and additions and replacements to existing generation facilities ($40 million).

               Oglethorpe’s cash and temporary cash investments totaled $227 million at December 31, 2003. Included in this amount was $133 million in restricted funds in connection with an issuance of PCBs in December 2003. (See “Refinancing Transactions” below.) Unrestricted cash balances decreased by $28 million from December 31, 2002 to December 31, 2003.

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               In addition to the $227 million in cash and temporary cash investments, Oglethorpe had, at December 31, 2003, $96 million in other short-term investments which represents a portion of its general funds invested with an external fund manager. The funds are invested primarily in high-quality short-term notes and bonds with an average maturity of approximately two years.

               Oglethorpe achieved a net margin of $17 million in 2003, which increased patronage capital (equity) by a like amount for total patronage capital of $444 million at December 31, 2003.

               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 2004 through 2006. Actual expenditures may vary from the estimates listed below because of factors such as changes in business conditions, fluctuating rates of load growth, 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.

Oglethorpe may be subject to future environmental regulations, including future implementation of existing laws and regulations. Beyond 2006, compliance with these future regulations could require capital expenditures exceeding $100 million, perhaps significantly so. Expenditures for environmental compliance will depend on, among others, the following factors:

               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 annually would result in greater amounts in Oglethorpe’s future operating expenses but would decrease the estimated amount of future capital expenditures. In any event, 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 possible future regulations applicable to Oglethorpe are pursuant to the Clean Air Act. The recently finalized regulations, proposed regulations and other actions that appear to be the most significant are described below.

               The U.S. Environmental Protection Agency (“EPA”) is in the process of implementing more stringent National Ambient Air Quality Standards (NAAQS) for both ozone and particulate matter. In connection with these NAAQS, EPA proposes to designate areas as attainment or nonattainment with these standards in 2004. Once such areas are designated as nonattainment for either ozone or particulate matter, further reductions in nitrogen oxides, sulfur dioxide, or both from either or both of Plant Wansley and Plant Scherer may be required.

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               In 1998, EPA issued a regulation calling for regional reductions in nitrogen oxides emissions from 22 states, including Georgia, which imposes a fixed cap on nitrogen oxides emissions from such states. The Georgia Environmental Protection Division has indicated that if Georgia must adhere to the regulation, it will require large fossil fuel-fired units, including those at Plant Wansley and Plant Scherer, to participate in achieving the required reductions. A pending challenge to EPA rules implementing these regulations could delay the currently proposed 2005 implementation date in Georgia. The co-owners of Scherer Units No. 1 and No. 2 have converted these units from bituminous coal to sub-bituminous coal, which substantially reduced the nitrogen oxides emissions from these units. Oglethorpe cannot determine at this time whether these regulations will requi re further controls to reduce nitrogen oxides emissions at either or both of Plant Wansley and Plant Scherer.

               In January of 2004, EPA proposed an interstate transport regulation that likely would require year round reductions in emissions of sulfur dioxide and nitrogen oxides from power plants, in two phases. The first phase would be in 2010, followed by a second phase in 2015. The rule could affect Georgia’s plans for attaining the NAAQS for ozone and particulate matter discussed above. Depending upon the outcome of this rulemaking, significant capital expenditures might be incurred at Plant Scherer, Plant Wansley or both.

               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. Further rulemaking in response to this decision could result in the installation of controls at either or both of Plant Wansley and Plant Scherer.

               EPA is considering other rulemaking with respect to sulfur dioxide and nitrogen oxides emissions as well.

               Several studies required by the Clean Air Act examined the health effects of power plant emissions of certain hazardous air pollutants. In late 2000, EPA concluded that mercury emissions from coal and oil-fired electric utility steam generating units should be regulated. In January of 2004, EPA proposed a regulation that would control emissions of mercury from such units in one of two ways – either by (1) requiring utilities to install “maximum achievable control technologies” by 2007; or (2) creating a market-based cap and trade program that would reduce emission of mercury in two phases, with the first phase coming in 2010 and the second in 2018. Depending on the outcome of such rulemaking, significant capital expenditures might be incurred at either or both of Plant Wansley and Plant Scherer.

               Financing for Acquisition of Talbot EMC and Chattahoochee EMC. In May 2003, Oglethorpe completed a transaction by which Talbot EMC and Chattahoochee EMC were merged with and into Oglethorpe. (See Note 5 and Note 14 of Notes to Financial Statements.) Pursuant to the merger, Oglethorpe succeeded to all of the assets and liabilities of Talbot EMC and Chattahoochee EMC. The assets consist of a 618 MW combustion turbine facility referred to as the Talbot Energy Facility and a 468 MW combined cycle facility referred to as the Chattahoochee Energy Facility. Oglethorpe is financing these generating facilities through two loans from the FFB, guaranteed by the RUS. At December 31, 2003, $565 million had been drawn under these loans, and Oglethorpe expects to receive its final loan advance of approximately $13 million in late 2004. Oglethorpe provided interim f inancing for these generating facilities through its commercial paper program. However, by December 31, 2003, sufficient funds had been drawn under the FFB loans to retire all outstanding commercial paper issued for this purpose.

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               The acquisition of these generating facilities increased Oglethorpe’s electric plant-in-service and long-term debt by $571 million and $565 million, respectively. The new FFB debt for these facilities is secured under Oglethorpe’s Mortgage Indenture. Since Oglethorpe’s margin requirement is based on a ratio applied to interest charges incurred for debt secured under the Mortgage Indenture, the increase in debt will result in an increase in the margin requirement of approximately $2.5 million in 2004 and will decrease thereafter as principal is repaid. The increase in assets and debt resulted in a one percent decrease in Oglethorpe’s equity to capitalization ratio and equity to asset ratio.

               Contractual Obligations. The table below reflects, as of December 31, 2003, Oglethorpe’s contractual obligations for the periods indicated.

               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), GTCassumed 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, 2003, the total obligation assumed by GTC relating to outstanding PCB principal was $122 million. As a result of a January 2004 refinancing transaction under which a portion of the PCB debt assumed by GTC was redeemed, GTC’s assumed obligation was reduced to $99 million. (See Note 5 of Notes to Financial State ments.) In 2004, GTC’s payments of principal and interest pursuant to this assumed obligation will be less than $6 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, 2003 would have been slightly less than $10 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 pumped storage hydroelectric project (“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 financed a portion of its payment to Oglethorpe 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 an 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 enter into payment undertaking agreements and funding agreements that provide for third parties (whose claims paying abilities or senior debt obligations are rated “AAA” by S&P and “Aaa” by Moody’s) to pay all of:

               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 equal rental payments to the owner trusts under the Facility Leases. In 2002, the amount of the rental payments under the Facility Subleases and Facility Leases each totaled $49 million. The payment undertaking agreements require the other party (the “payment undertaker”) to pay the rent payments directly to the lender of the owner trust 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 Lease s 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.

               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 financial statements of RMLC and Oglethorpe do not reflect the payment undertaking agreements, the payments made by the payment undertaker or the payment of rent under the Facility Subleases or Facility Leases. At December 31, 2002, if RMLC’s rent payment obligations under the Facility Leases and RMLC’s interests in the related payment undertaking agreements were reflected on the financial statements of RMLC and Oglethorpe, both amounts would equal $705 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 $1.088 billion for all six Facility Leases. The payment undertaking agreements and funding agreements would fund $716 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 Oglethorpe returns through RMLC any undivided interest in Rocky Mountain to an owner trust, that owner trust has several options it can elect. Each of these options is structured to assure that the owner trust’s net economic benefit will be no less than if RMLC had purchased that undivided interest in Rocky Mountain under the purchase option set forth in the applicable Facility Lease. The options available to the owner trust include:

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

Liquidity and Sources of Capital

               Sources of Capital. Oglethorpe has obtained the majority of its long-term financing from RUS guaranteed loans funded by FFB. Oglethorpe has also obtained a substantial portion of its long-term financing requirements from the issuance of PCBs.

               In addition, Oglethorpe’s operations have consistently 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. Oglethorpe anticipates that it will continue to meet these types of capital requirements through 2006 primarily with funds generated from operations and, if necessary, with short-term borrowings. However, in the future Oglethorpe may also pursue long-term financing for these types of capital expenditures. (See “Other Planned Financings” below.)

               To meet short-term cash needs and liquidity requirements, Oglethorpe had, as of December 31, 2003, (i) approximately $227 million in cash and temporary cash investments, (ii) $96 million in other short-term investments, (iii) $20 million available under a letter of credit with the National Rural Utilities Cooperative Finance Corporation (“CFC”), and (iv) up to $395 million available under the following committed line of credit (“LOC”) facilities:

               Oglethorpe has a commercial paper program under which it 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 $295 million committed backup facility provided by a group of eight banks that was syndicated by Bank of America. Along with the CoBank and CFC lines of credit, the facility supporting the commercial paper may also be used for general working capital needs. However, any amounts drawn under the commercial paper facility for working capital and general purposes 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 two interest rate swaps relating to PCB transactions and the Rocky Mountain lease transactions. The amount of liquidity required under these agreements was $74 million as of December 31, 2003, and Oglethorpe had sufficient liquidity to satisfy these requirements.

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               Credit Rating Risk

               Oglethorpe has financial agreements and commercial contracts 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 Oglethorpe’s current ratings and the more significant ratings triggers contained in Oglethorpe’s agreements and contracts.

               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 as of December 31, 2003, a termination of the swap would require Oglethorpe to make a termination payment of approximately $50 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 yea rs.

               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 $50 million in liquidity.

               Under the Morgan Stanley power marketing arrangements, which expire March 31, 2005, Oglethorpe could be required to provide credit assurance up to $30 million if Oglethorpe fails to maintain at least two of the three ratings shown in the table above.

               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 agreements and contracts 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.

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 $198 million under this program, including $34 million of PCB principal that matured on January 1, 2004. Oglethorpe plans to continue this refinancing program through at least 2007, covering an additional $49 million in PCB principal maturities.

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               Along with the $34 million of PCB principal that was refinanced as discussed above, Oglethorpe refinanced an additional $105 million in PCBs that reached their first call date on January 1, 2004. In conjunction with this combined transaction, $133 million in refunding PCBs were issued in December 2003.

               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 $7 million and received cash of $16.3 million on the $23.3 million due from GTC in connection with the $133 million refinancing discussed above. GTC is currently evaluating its options with respect to the planned refinancings of PCB principal maturities through 2007.

               In September 2003, Oglethorpe closed a $29 million fifteen-year operating lease financing for 523 rail cars. The rail cars are used to transport coal from various locations in the United States to Plants Scherer and Wansley in Georgia.

               The average interest rate on long-term debt and capital lease obligations was 5.19% at December 31, 2003.

               Other Planned Financings

               Oglethorpe anticipates submitting two loan applications totaling approximately $135 million to the RUS in mid and late 2004. If approved, one loan will reimburse Oglethorpe for prior capital expenditures made in complying with environmental regulations, and the other loan will cover current and upcoming normal additions and replacements to generation facilities. This debt would be funded through the FFB and guaranteed by the RUS and would be secured under Oglethorpe’s Mortgage Indenture.

               Oglethorpe is also monitoring the current historically low interest rate environment and may decide to take advantage of other refinancing opportunities, such as converting a portion of its existing tax-exempt PCB debt from a variable rate to a fixed rate of interest.

               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 to manage this volatility and does not use derivatives for speculative purposes.  (See “Oglethorpe Power Corporation—Electric Rates” for further discussion on Oglethorpe’s rate structure.)

               Oglethorpe’s Risk Management Committee provides general oversight over all risk management activities, including commodity trading, fuels management, insurance procurement, debt management and investment portfolio management. The Risk Management Committee is comprised of senior executive officers, including the Chief Executive Officer and the Chief Operating Officer. The Risk Management committee has implemented comprehensive risk management policies to manage and monitor credit and market price risks. These policies also specify controls and authorization levels related to various risk management activities. The Risk Management Committee frequently meets to review corporate exposures, risk management strategies, and hedge positions. The Risk Management committee regularly reports corporate exposures and risk management activities to the Audit Committe e 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, 2003, Oglethorpe had 19% of its debt in a variable rate mode.

               The table below details Oglethorpe’s existing debt instruments and provides the fair value at December 31, 2003, the outstanding balance at the beginning and end of each year and the annual principal maturities and associated average interest rates.