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

FORM 10-K

(Mark One)
ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2007
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From                            to
Commission File No. 33-7591

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

Georgia (State or other jurisdiction of incorporation or organization)			58-1211925 (I.R.S. employer identification no.)
2100 East Exchange Place Tucker, Georgia (Address of principal executive offices)			30084-5336 (Zip Code)
		Registrant's telephone number, including area code:	(770) 270-7600
		Securities registered pursuant to Section 12(b) of the Act:	None
	Securities registered pursuant to Section 12(g) of the Act:		None

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

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

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

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

       Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer," and "smaller reporting company" in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer o Accelerated filer o Non-accelerated filer (Do not check if a smaller reporting company) ý Smaller reporting company o

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

       State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter. None

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

       Documents Incorporated by Reference: None

OGLETHORPE POWER CORPORATION

2007 FORM 10-K ANNUAL REPORT

Table of Contents

ITEM		Page
PART I
1	Business	1
	Oglethorpe Power Corporation	1
	Oglethorpe's Power Supply Resources	7
	The Members and Their Power Supply Resources	9
	Environmental and Other Regulation	13
1A	Risk Factors	19
1B	Unresolved Staff Comments	22
2	Properties	23
3	Legal Proceedings	28
4	Submission of Matters to a Vote of Security Holders	28
PART II
5	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
6	Selected Financial Data	29
7	Management's Discussion and Analysis of Financial Condition and Results of Operations	30
7A	Quantitative and Qualitative Disclosures About Market Risk	45
8	Financial Statements and Supplementary Data	49
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	78
9A	Controls and Procedures	78
9B	Other Information	79
PART III
10	Directors, Executive Officers and Corporate Governance	80
11	Executive Compensation	84
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	93
13	Certain Relationships and Related Transactions, and Director Independence	93
14	Principal Accountant Fees and Services	94
PART IV
15	Exhibits and Financial Statement Schedules	95
	SIGNATURES	111

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SELECTED DEFINITIONS

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

Term	Meaning
CFC	National Rural Utilities Cooperative Finance Corporation
EMC	Electric Membership Corporation
FERC	Federal Energy Regulatory Commission
FFB	Federal Financing Bank
GPC	Georgia Power Company
GPSC	Georgia Public Service Commission
GSOC	Georgia System Operations Corporation
GTC	Georgia Transmission Corporation (An Electric Membership Corporation)
MEAG	Municipal Electric Authority of Georgia
NRC	Nuclear Regulatory Commission
RUS	Rural Utilities Service
SEPA	Southeastern Power Administration
SNOC	Southern Nuclear Operating Company

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PART I

ITEM 1. BUSINESS

OGLETHORPE POWER CORPORATION

General

    Oglethorpe Power Corporation (An Electric Membership Corporation) ("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta. Oglethorpe is owned by 38 retail electric distribution cooperative members (the "Members"). Oglethorpe's principal business is providing wholesale electric power to the Members. As with cooperatives generally, Oglethorpe operates on a not-for-profit basis. Oglethorpe is the largest electric cooperative in the United States in terms of assets, kilowatt-hour ("kWh") sales and, through the Members, consumers served, and is also the second largest power supplier in the state of Georgia. Oglethorpe has 160 employees.

    The Members are local consumer-owned distribution cooperatives providing retail electric service on a not-for-profit basis. In general, the customer base of the Members consists of residential, commercial and industrial consumers within specific geographic areas. The Members serve approximately 1.7 million electric consumers (meters) representing approximately 4.1 million people. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES.")

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

Cooperative Principles

    Cooperatives like Oglethorpe are business organizations owned by their members, which are also either their wholesale or retail customers. As not-for-profit organizations, cooperatives are intended to provide services to their members at the lowest possible cost, in part by eliminating the need to produce profits or a return on equity. Cooperatives may make sales to non-members, the effect of which is generally to reduce costs to members. Today, cooperatives operate throughout the United States in such diverse areas as utilities, agriculture, irrigation, insurance and credit.

    All cooperatives are based on similar business principles and legal foundations. Generally, an electric cooperative designs its rates to recover its cost-of-service and to collect a reasonable amount of revenues in excess of expenses, which constitutes margins. The margins increase patronage capital, which is the equity component of a cooperative's capitalization. Any such margins are considered capital contributions (that is, equity) from the members and are held for the accounts of the members and returned to them when the board of directors of the cooperative deems it prudent to do so. The timing and amount of any actual return of capital to the members depends on the financial goals of the cooperative and the cooperative's loan and security agreements.

Power Supply Business

    Oglethorpe provides wholesale electric service to the 38 Members for a substantial portion of their power requirements from a combination of its generation assets and power purchased from power marketers and other suppliers. Oglethorpe provides this service pursuant to long-term, take-or-pay Amended and Restated Wholesale Power Contracts, dated January 1, 2003, and amended as of June 1, 2005 (the "Wholesale Power Contracts"). The Wholesale Power Contracts obligate the Members jointly and severally to pay rates sufficient to recover all the costs of owning and operating Oglethorpe's power supply business. The Members satisfy all of their power requirements above their Oglethorpe purchase obligations with purchases from other suppliers. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.")

    Oglethorpe has interests in 24 generating units. These units provide Oglethorpe with a total of 4,744 megawatts ("MW") of nameplate capacity, consisting of 1,501 MW of coal-fired capacity, 1,185 MW of nuclear-fueled capacity, 632 MW of pumped storage hydroelectric capacity, 1,411 MW of gas-fired capacity (206 MW of which is capable of running on oil) and 15 MW of oil-fired combustion turbine capacity.

    Oglethorpe also purchases approximately 300 MW of power pursuant to a long-term power purchase agreement. (See "OGLETHORPE'S POWER SUPPLY RESOURCES" and "PROPERTIES – Generating Facilities.")

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    In 2007, three of Oglethorpe's Members, Cobb EMC, Jackson EMC and Sawnee EMC, accounted for 13.3 percent, 12.3 percent and 10.0 percent of Oglethorpe's total revenues, respectively. None of the other Members accounted for as much as 10 percent of Oglethorpe's total revenues in 2007.

Wholesale Power Contracts

    Oglethorpe has substantially similar Wholesale Power Contracts with each Member extending through December 31, 2050. Under the Wholesale Power Contracts, each Member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs (referred to as a "percentage capacity responsibility") of each of Oglethorpe's generation and purchased power resources. Each Wholesale Power Contract specifically provides that the Member must make payments whether or not power is delivered and whether or not a plant has been sold or is otherwise unavailable. Oglethorpe is obligated to use its reasonable best efforts to operate, maintain and manage its resources in accordance with prudent utility practices.

    Percentage capacity responsibilities have been assigned to all of Oglethorpe's generation and purchased power resources. Percentage capacity responsibilities for any future resource will be assigned only to Members choosing to participate in that resource. The Wholesale Power Contracts provide that each Member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for any approved future resources (as described below), whether or not such Member has elected to participate in such future resource. For resources so approved in which less than all Members participate, costs are shared first among the participating Members, and if all participating Members default, each non-participating Member is expressly obligated to pay a proportionate share of such default.

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

    Under the Wholesale Power Contracts, Oglethorpe is not obligated to provide all of the Members' capacity and energy requirements. Individual Members must satisfy all of their requirements above their Oglethorpe purchase obligations from other suppliers, unless Oglethorpe and the Members agree that Oglethorpe will supply additional capacity and associated energy, subject to the approval requirements described above. In 2007, energy supplied by Oglethorpe accounted for approximately 63 percent of the Members' retail energy requirements. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.")

    Under the Wholesale Power Contracts, each Member must establish rates and conduct its business in a manner that will enable the Member to pay (i) to Oglethorpe when due, all amounts payable by the Member under its Wholesale Power Contract and (ii) any and all other amounts payable from, or which might constitute a charge or a lien upon, the revenues and receipts derived from the Member's electric system, including all operation and maintenance expenses and the principal of, premium, if any, and interest on all indebtedness related to the Member's electric system.

New Business Model Member Agreement

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

    Oglethorpe may not provide services unrelated to its resources or its functions under the Wholesale Power Contracts if such services would require it to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75 percent of Oglethorpe's Board of Directors, 75 percent of the Members, and Members representing 75 percent of the patronage capital of Oglethorpe. Oglethorpe may provide any other unrelated service to a Member so long as (i) doing so would not create a conflict of interest with respect to other Members, (ii) such service is being provided to all Members or (iii) such service has received the 75 percent approvals described above.

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Electric Rates

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

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

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

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

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

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

    The formulary rate established by Oglethorpe in the rate schedule to the Wholesale Power Contracts employs a rate methodology under which all categories of costs are specifically separated as components of the formula to determine Oglethorpe's revenue requirements. The rate schedule also implements the responsibility for fixed costs assigned to each Member (that is, the Member's percentage capacity responsibility). The monthly charges for capacity and other non-energy charges are based on Oglethorpe's annual budget. Such capacity and other non-energy charges may be adjusted by the Board of Directors, if necessary, during the year through an adjustment to the annual budget. Energy charges reflect the pass-through of actual energy costs, including fuel costs, variable operations and maintenance costs and purchased energy costs. (See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Summary of Cooperative Operations – Rates and Regulation.")

    The rate schedule formula also includes a prior period adjustment mechanism designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum 1.10 Margins for Interest Ratio are accrued as of December 31 of the applicable year and collected from the Members during the period April through December of the following year. The rate schedule formula is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses recorded by Oglethorpe, plus amounts necessary to achieve at least the minimum 1.10 Margins for Interest Ratio.

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

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Relationship with Smarr EMC

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

Relationship with GTC

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

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

    GTC has rights in the Integrated Transmission System, which consists of transmission facilities owned by GTC, Georgia Power Company ("GPC"), the Municipal Electric Authority of Georgia ("MEAG") and the City of Dalton ("Dalton"). Through agreements, common access to the combined facilities that compose the Integrated Transmission System enables the owners to use their combined resources to make deliveries to or for their respective consumers, to provide transmission service to third parties and to make off-system purchases and sales. The Integrated Transmission System was established in order to obtain the benefits of a coordinated development of the parties' transmission facilities and to make it unnecessary for any party to construct duplicative facilities.

Relationship with GSOC

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

    Oglethorpe has a modest amount of loans (approximately $10 million) outstanding to GSOC, primarily for the purpose of financing capital expenditures. GSOC has an additional $5 million that can be drawn under one of its loans with Oglethorpe.

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

Relationship with RUS

    Historically, federal loan programs administered by RUS have provided the principal source of financing for electric cooperatives. Loans guaranteed by RUS and made by the Federal Financing Bank ("FFB") have been a major source of funding for Oglethorpe. However, the availability and magnitude of RUS-guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, RUS-guaranteed loan funds are subject to increased uncertainty because of budgetary pressures faced by Congress. The budget proposal for fiscal year 2009 submitted by President Bush asserts that the RUS loan program is no longer necessary for the construction of new generating plants. Further, RUS has indicated that the Administration's position is that RUS will no longer provide loan guarantees for new baseload generation. However, the budget proposal also indicates

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that loan levels for such generation may be considered when Congress authorizes a fee for such loans. Such legislation is currently under consideration. Although Congress has historically rejected proposals to dramatically curtail the RUS loan program, there can be no assurances that it will continue to do so. Because of these factors, Oglethorpe cannot predict the amount or cost of RUS-guaranteed loans that may be available to Oglethorpe in the future.

    Oglethorpe has a loan contract with RUS in connection with the Mortgage Indenture. Under the loan contract, RUS has approval rights over certain significant actions and arrangements, including, without limitation,

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significant additions to or dispositions of system assets,

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significant power purchase and sale contracts,

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

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changes to plant ownership and operating agreements, and

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in limited circumstances, issuance of additional secured debt.

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

Relationship with GPC

    Oglethorpe's relationship with GPC is a significant factor in several aspects of Oglethorpe's business. GPC is responsible for the operation of all of Oglethorpe's co-owned generating facilities, except Rocky Mountain, on behalf of itself as a co-owner and as agent for the other co-owners. GPC supplies services to Oglethorpe and GSOC to support the scheduling and dispatch of Oglethorpe's resources, including off-system transactions. GPC and the Members are competitors in the State of Georgia for electric service to any new customer that has a choice of supplier under the Georgia Territorial Electric Service Act, which was enacted in 1973 (the "Territorial Act"). For further information regarding the agreements with GPC and Oglethorpe's and the Members' relationships with GPC, see "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Service Area and Competition" herein and "PROPERTIES – Fuel Supply," "– Co-Owners of Plants – Georgia Power Company" and "– The Plant Agreements."

Competition

    Under current Georgia law, the Members generally have the exclusive right to provide retail electric service in their respective territories. Since 1973, however, the Territorial Act has permitted limited competition among electric utilities located in Georgia for sales of electricity to certain large commercial or industrial customers. The owner of any new facility may receive electric service from the power supplier of its choice if the facility is located outside of municipal limits and has a connected load upon initial full operation of 900 kilowatts or more. The Members are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. While the competition for 900-kilowatt loads represents only limited competition in Georgia, this competition has given the Members the opportunity to develop resources and strategies to prepare for a more competitive market.

    Some states have implemented varying forms of retail competition among power suppliers. No legislation related to retail competition has yet been enacted in Georgia, and no bill is currently pending in the Georgia legislature which would amend the Territorial Act or otherwise affect the exclusive right of the Members to supply power to their current service territories. The GPSC does not have the authority under Georgia law to order retail competition or amend the Territorial Act.

    Oglethorpe cannot predict at this time the outcome of the various developments that may lead to increased competition in the electric utility industry or the effect of such developments on Oglethorpe or the Members. Nonetheless, Oglethorpe has taken several steps to prepare for and adapt to the fundamental changes that have occurred or appear likely to occur in the electric utility industry and to reduce potential stranded costs. In 1997, Oglethorpe divided itself into separate generation, transmission and system operations companies in order to better serve its Members in a deregulated and

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competitive environment. Oglethorpe also implemented an interest cost reduction program, which included refinancings and prepayments of various debt issues that significantly reduced annual interest expense.

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

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power marketing arrangements or other alliance arrangements;

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

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changing the current mix of ownership and purchase arrangements used to meet power supply requirements;

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construction or acquisition of power supply resources, whether owned by Oglethorpe or by other entities;

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use of power purchase contracts to meet power supply requirements, and whether to use short, medium or long-term contracts, or a mix of terms;

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participation in future power supply resources developed by others, whether by ownership or long-term purchase commitment;

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

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extensions of nuclear facility licenses;

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additional maturity extensions of existing indebtedness;

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potential prepayment of debt;

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various responses to the proliferation of non-core services offered by electric utilities;

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mergers or other combinations among distributors or power suppliers; and

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other regulatory and business changes that may affect relative values of generation classes or have impacts on the electric industry.

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

    Many Members are also providing or considering proposals to provide non-traditional products and services such as telecommunications and other services. In 2002, the Georgia legislature enacted legislation empowering the GPSC to authorize Member affiliates to market natural gas. The GPSC is required to condition such authorization on terms designed to ensure that cross-subsidizations do not occur between the electricity services of a Member and the gas activities of its gas affiliates.

    Depending on the nature of the generation business in Georgia, there could be reasons for the Members to separate their physical distribution business from their energy business, or otherwise restructure their current businesses to operate more effectively.

    Further, a Member's power supply planning may include consideration of assignment of its rights and obligations under its Wholesale Power Contract to another Member or a third party. Oglethorpe has existing provisions for Wholesale Power Contract assignment, as well as provisions for a Member to withdraw and concurrently to assign its rights and obligations under its Wholesale Power Contract. Assignments upon withdrawal require the assignee to have certain published credit ratings and to assume all of the withdrawing Member's obligations under its Wholesale Power Contract with Oglethorpe, and must be approved by Oglethorpe's Board of Directors. Assignments without withdrawal are governed by the Wholesale Power Contract and must be approved by both Oglethorpe's Board of Directors and RUS.

    From time to time, individual Members may be approached by parties indicating an interest in purchasing their systems. A Member generally must obtain approval from Oglethorpe before it may consolidate or merge with any person or reorganize or change the form of its business organization from an electric membership corporation or sell, transfer, lease or otherwise dispose of all or substantially all of its assets to any person, whether in a single transaction or series of transactions. The Member may enter into such a transaction without Oglethorpe's approval if specified conditions are satisfied, including, but not limited to, an agreement by the transferee, satisfactory to Oglethorpe,

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to assume the obligations of the Member under the Wholesale Power Contract, and certifications of accountants as to certain specified financial requirements of the transferee. The Wholesale Power Contracts also provide that a Member may not dissolve, liquidate or otherwise wind up its affairs without Oglethorpe's approval.

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

Seasonal Variations

    The demand for energy by the Members is influenced by seasonal weather conditions. Historically, Oglethorpe's peak sales have occurred during the months of June through August. Energy revenues track energy costs as they are incurred and also fluctuate month to month. Capacity revenues reflect the recovery of Oglethorpe's fixed costs, which do not vary significantly from month to month; therefore, capacity charges are billed and capacity revenues are recognized in substantially equal monthly amounts.

OGLETHORPE'S POWER SUPPLY RESOURCES

General

    Oglethorpe supplies capacity and energy to the Members for a portion of their requirements from a combination of its generating assets and power purchased from other suppliers. In 2007, energy supplied by Oglethorpe accounted for approximately 63 percent of the Members' retail energy requirements.

Generating Plants

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

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

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

Power Purchase and Sale Arrangements

Power Purchases

    Oglethorpe has a contract through 2019 to purchase approximately 300 MW of capacity from Hartwell Energy Limited Partnership, a joint venture between Bicent Power LLC, and American National Power, Inc., a subsidiary of International Power PLC. This capacity is provided by two 150 MW gas-fired combustion turbine generating units on a site near Hartwell, Georgia. Oglethorpe has the right to dispatch the units.

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    Oglethorpe has an agreement with Morgan Stanley Capital Group, Inc. under which it purchased 153 MW in 2007 and will purchase 166 MW in 2008, along with fixed quantities of energy.

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

    In addition, Oglethorpe also purchases small amounts of capacity and energy from "qualifying facilities" under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Under a waiver order from the Federal Energy Regulatory Commission ("FERC"), Oglethorpe historically made all purchases the Members would have otherwise been required to make under PURPA and Oglethorpe was relieved of its obligation to sell certain services to "qualifying facilities" so long as the Members make those sales. Purchases by Oglethorpe from such qualifying facilities provided less than 0.1 percent of Oglethorpe's energy requirements for the Members in 2007. Under their Wholesale Power Contracts, the Members may now make such purchases instead of Oglethorpe.

Other Power System Arrangements

    Oglethorpe has interchange, transmission and/or short-term capacity and energy purchase or sale agreements with approximately 50 utilities, power marketers and other power suppliers. The agreements provide variously for the purchase and/or sale of capacity and energy and/or for the purchase of transmission service. Oglethorpe is currently using only about one-third of these agreements, primarily to facilitate the short-term management of its resource portfolio.

Future Power Resources

    In 2005, the co-owners of Plant Vogtle executed an agreement regarding exploration of development of up to two additional nuclear units at the Plant Vogtle site. Oglethorpe has the option to participate in up to 30 percent of any new project. The co-owners have entered into participation agreements that would govern the rights and obligations of co-owners of the additional units, if any. Oglethorpe is currently participating with the co-owners in the costs of pursuing this option, including preparation and filing of applications to the Nuclear Regulatory Commission ("NRC") for the appropriate permits and licenses. GPC is pursuing a license application schedule that could support a commercial operation date as early as 2016, including the filing in 2006 of an application for an Early Site Permit. The extent of Oglethorpe's ultimate involvement, if any, will be determined within the next year. Oglethorpe may ultimately elect not to participate in any unit that may be constructed, or elect to participate at less or more (under certain circumstances arising from reduced participation by other co-owners) than its current 30 percent participation. See "MANAGEMENT DISCUSSION AND ANALYSIS – Financial Condition – Financing Activities" for information about preliminary steps Oglethorpe has taken to procure financing in the event it elects to participate. To the extent Oglethorpe decides not to participate or reduces its participation, GPC will refund all or a pro rata share of the amounts paid by Oglethorpe, with interest. Prior to making a final election to participate, Oglethorpe must obtain the Board of Directors and Member approvals required by the Wholesale Power Contracts (see "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts") as well as RUS approval.

    From time to time, Oglethorpe may assist the Members in investigating potential new power supply resources, after compliance with the terms of the New Business Model Member Agreement (see "OGLETHORPE POWER CORPORATION – New Business Model Member Agreement"). The Members have requested that Oglethorpe assist them with an evaluation of future power supply needs. In working with the Members, Oglethorpe has identified resources to meet the future power supply needs of the Members over the next ten years, including gas, coal, nuclear and renewable generation alternatives. Oglethorpe is prepared to assist in the development of those resources when approved by the Members in accordance with the Wholesale Power Contracts.

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THE MEMBERS AND THEIR POWER SUPPLY RESOURCES

Member Demand and Energy Requirements

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

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

    The Members serve approximately 1.7 million electric consumers (meters) representing approximately 4.1 million people. The Members serve a region covering approximately 37,000 square miles, which is approximately 65 percent of the land area in the State of Georgia, encompassing 150 of the State's 159 counties. Sales by the Members in 2007 amounted to approximately 35 million megawatt hours ("MWh"), with approximately 67 percent to residential consumers, 30 percent to commercial and industrial consumers and 3 percent to other consumers. The Members are the principal suppliers for the power needs of rural Georgia. While the Members do not serve any major cities, portions of their service territories are in close proximity to urban areas and are experiencing substantial growth due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. The 38 Members have experienced approximate average annual compound growth rates from 2005 through 2007 of 3 percent in number of consumers, 3 percent in MWh sales and 7 percent in electric revenues.

    The following table shows the aggregate peak demand and energy requirements of the 38 Members for the years 2005 through 2007, and also shows the amounts of energy requirements supplied by Oglethorpe. From 2005 through 2007, demand and energy requirements of the Members increased at an average annual compound growth rate of 5.5 percent and 3.4 percent, respectively.

	Member Demand (MW)	Member Energy Requirements (MWh)
	Total(1)	Total(2)	Supplied by Oglethorpe(3)
2005	7,998	33,618,746	23,721,939
2006	8,094	34,973,868	23,019,482
2007	8,907	35,944,150	22,815,174

(1)

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

(2)

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

(3)

Includes energy supplied to Members for resale at wholesale.

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Service Area and Competition

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

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

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

Cooperative Structure

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

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

    Oglethorpe depends on the revenue received by it from the Members pursuant to the Wholesale Power Contracts to cover the costs of the operation of its power supply business and satisfy its debt service obligations.

Rate Regulation of Members

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

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less than 1.10, in each case for the two highest out of every three successive years.

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

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

Members' Relationship with RUS

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

    Historically, federal loan programs providing direct loans from RUS to electric cooperatives have been a major source of funding for the Members. Under the current RUS loan programs, distribution borrowers are eligible for loans made by FFB or other lenders and guaranteed by RUS. Certain borrowers with either low consumer density or higher than average rates and lower than average consumer income are eligible for special loans that bear interest at an annual rate of 5 percent. However, the availability and magnitude of RUS direct and guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, the availability of RUS loan funds is subject to increased uncertainty because of budgetary pressures faced by Congress. In its 2009 budget proposal, the Bush administration has requested a decrease in funding for the guaranteed loan program, which provides funding for generation and transmission borrowers, as well as distribution borrowers. Oglethorpe cannot predict the amount or cost of RUS direct and guaranteed loans that may be available to the Members in the future.

Members' Relationships with GTC and GSOC

    GTC provides transmission services to the Members for delivery of the Members' power purchases from Oglethorpe and other power suppliers. GTC and the Members have entered into Member Transmission Service Agreements (the "MTSAs") under which GTC provides transmission service to the Members pursuant to a transmission tariff. The MTSAs have a minimum term for network service until December 31, 2040. However, the MTSAs include certain elections for load growth above 1995 requirements, with notice to GTC, to be served by others. The MTSAs provide that if a Member elects to purchase a part of its network service elsewhere, it must pay appropriate stranded costs to protect the other Members from any rate increase that they could otherwise occur. Under the MTSAs, Members have the right to design, construct and own new distribution substations.

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

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

Member Power Supply Resources

Oglethorpe Power Corporation

    In 2007, energy supplied by Oglethorpe accounted for approximately 63 percent of the Members' retail energy requirements. Each Member has a take-or-pay, fixed percentage capacity responsibility for all of Oglethorpe's existing resources. (See "OGLETHORPE POWER CORPORATION – Wholesale Power Contracts.") The Members satisfied all of their requirements above

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their Oglethorpe purchase obligations with purchases from other suppliers as described below.

Contracts with SEPA

    The Members purchase hydroelectric power from the Southeastern Power Administration ("SEPA") under contracts that extend until 2016. In 2007, the aggregate SEPA allocation to the Members was 562 MW plus associated energy. Each Member must schedule its energy allocation, and each Member has designated Oglethorpe to perform this function. Pursuant to a separate agreement, Oglethorpe schedules, through GSOC, the Members' SEPA power deliveries. Further, each Member may be required, if certain conditions are met, to contribute funds for capital improvements for Corps of Engineers projects from which its allocation is derived in order to retain the allocation.

Smarr EMC

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

GPC Block Purchase

    Twenty-nine Members have entered into 10-year power supply contracts with GPC under which they will purchase an aggregate of 675 MW of capacity and associated energy. Delivery under the agreements began January 1, 2005.

Other Member Resources

    Members are obtaining their other power supply requirements from various sources. Thirty Members have entered into contracts with third parties for all of their incremental power requirements, with remaining terms ranging from 3 to 10 years. The other Members use a portfolio of power purchase contracts to meet their requirements.

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

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

    In addition to future power supply resources that Oglethorpe may acquire for the Members, the Members will likely also continue to acquire future resources from other suppliers, including suppliers that may be owned by Members.

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ENVIRONMENTAL AND OTHER REGULATION

General

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

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

    Compliance with environmental standards will continue to be reflected in Oglethorpe's capital expenditures and operating costs. Oglethorpe made environmentally related capital expenditures of $82 million in 2007 and forecasts capital expenditures of approximately $186 million, $152 million and $114 million in 2008, 2009 and 2010, respectively, to maintain and achieve compliance with current and anticipated environmental requirements. For a further discussion of expected future capital expenditures to comply with environmental requirements and regulations, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Capital Requirements – Capital Expenditures."

Clean Air Act

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

    Sulfur dioxide reductions are being imposed through a sulfur dioxide emission allowance trading program established under the 1990 amendments to the Clean Air Act. Pursuant to regulations issued by the U.S. Environmental Protection Agency ("EPA"), aggregate emissions of sulfur dioxide from all affected units are now capped at 8.9 million tons per year. Tradable emission allowances, which authorize the emission of one ton of sulfur dioxide during a particular calendar year or thereafter, are issued 30 years in advance and are transferable. Oglethorpe is currently complying with this program by using lower-sulfur fuel and emission allowances. Installation of flue gas desulfurization equipment ("scrubbers") is underway at Plant Wansley and is in the design phase at Plant Scherer to comply with implementing regulations issued by the State of Georgia.

    Reductions in nitrogen oxides emissions were also imposed, under the prior 1-hour National Ambient Air Quality Standard ("NAAQS") for ozone, requiring the installation of new control equipment. Significant reductions in nitrogen oxides emissions were achieved, due to the selective catalytic reduction systems installed at Plant Wansley and the separated overfire air systems installed at Plant Scherer.

    Other recently finalized regulations, proposed regulations and other actions could result in more stringent controls on all emissions, including utility emissions, in the future. The actions that appear to be the most significant are described below. These regulatory programs affect existing fossil-fuel-fired generating facilities, and could also impact future fossil-fuel-fired generating plants.

    8-hour Ozone NAAQS.    When the old 1-hour ozone NAAQS was replaced with the new 8-hour standard, the Atlanta ozone nonattainment area was expanded in 2005 from its original 13 counties to 20 counties, and the Macon ozone nonattainment area (which includes Plant Scherer) was created. Rulemakings to implement the 8-hour standard remain in litigation. The Atlanta area is being re-classified to a more stringent nonattainment status, while the Macon area has been designated to be in attainment. A state implementation plan to bring the Atlanta area into attainment is due at the end of 2008. Further, EPA has recently tightened the 8-hour

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standards. Implementation of the new standards will be subject to future rulemaking.

    Particulate matter NAAQS.    Plants Wansley and Scherer are in the area designated in 2005 as nonattainment of the fine particulate matter standards first established in 1997. Subsequently, in 2006, the 1997 standards were tightened. New nonattainment designations for the 2006 standards have not yet been made, but the area is likely to remain in nonattainment status. Implementation of the 2006 standards will be the subject of future rulemaking. An implementation rule was finalized in 2007 setting forth how the original 1997 standards are to be met, and state implementation plans ("SIPs") for achieving 1997 standards are due in 2008. Litigation on these EPA actions is continuing.

    Regional NO_X SIP Call.    In 1998, EPA promulgated a regulation for a 22-state region, which includes Georgia, and a separate April 2004 rule, which imposed a cap on nitrogen oxides emissions in the affected region, and required each state in the affected region to revise its SIP to implement such reductions. In 2005, EPA stayed the implementation of that rule as it would apply to Georgia. In 2007, EPA proposed to continue the stay and to delete Georgia from this regulation.

    Clean Air Interstate Rule.    EPA finalized a clean air interstate rule in 2005 for ozone and fine particulate matter that requires emissions reductions in sulfur dioxide and nitrogen oxides in most eastern states, including Georgia. The rule established a market-based cap and trade program, with emission caps for each affected state. Litigation challenging the final rule continues. Under Georgia's state implementation plan, which now includes the rule, the caps would be implemented in two phases. The first phase, for nitrogen oxides caps, becomes effective in 2009 and, for sulfur dioxide caps, in 2010. A second phase for both pollutants follows in 2015. Year-round operation of the selective catalytic reduction systems already installed at Plant Wansley and additional controls at Plant Scherer may be needed to comply with the state implementation plan.

    Regional Haze.    EPA's 1999 regional haze rule was created for the control of certain sources that emit nitrogen oxides or sulfur dioxide that contribute to the degradation of visibility in mandatory federal Class I areas, such as national parks and wilderness areas. A revised rule was issued in 2005 to address portions of the 1999 rule remanded to EPA. Another rule and guidance to implement the regional haze rule were also proposed by EPA in 2005. The goal of the regional haze rule is to restore natural visibility conditions in the Class I areas by 2064. Interim milestones reflecting reasonable progress towards this goal are required beginning in 2018. Moreover, the rule requires the application of Best Available Retrofit Technology ("BART") for a certain class of sources (including Plants Scherer and Wansley) contributing to the impairment of visibility in the Class I areas. The Georgia state implementation plan to implement BART and reasonable further progress originally due in December 2007 is under development and will not be finalized until the end of 2008 at the earliest. Until such rules are finalized and implemented by the State of Georgia, Oglethorpe will not know what additional controls, if any, may be required at Plant Scherer to comply with this rule.

    Short-term NAAQS for Sulfur Dioxide.    Although EPA had decided not to impose a new NAAQS for sulfur dioxide, that decision remains remanded to EPA for further rulemaking.

    Clean Air Mercury Rule and State-Related Mercury Rules.    In 2005, EPA finalized a regulation that would control emissions of mercury, by creating a market-based cap-and-trade program that would reduce emissions of mercury in two phases, with the first phase becoming effective in 2010 and the second in 2018. In litigation challenging the rule, in early 2008, the U.S. Court of Appeals for the D.C. Circuit vacated and remanded the cap-and-trade rule and a companion rule delisting electric generating units from the hazardous air pollutant source list in Section 112 of the Clean Air Act. That litigation may continue. Although Georgia, prior to this decision, elected to include the EPA cap-and-trade program in its state implementation plan, this litigation may affect the continued validity of Georgia's plan. Moreover, Georgia's new mercury rules also finalized in 2007 include a "multi-pollutant rule" that requires operation of the existing selective catalytic reduction system (nitrogen oxides) and the scrubber (sulfur dioxide and mercury) being constructed at Plant Wansley as well as additional controls for mercury (activated carbon injection and baghouse), sulfur dioxide (scrubber) and nitrogen oxides (selective catalytic reduction system) at Plant Scherer. Whether the litigation will affect this portion of Georgia's mercury rules is unknown at this time.

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    Oglethorpe believes that the controls being designed and/or installed at Plants Wansley and Scherer will meet the requirements of the rules described above. However, because (1) several of these proposed or final Clean Air Act regulations could require control of the same emissions, (2) the compliance requirements remain uncertain, and (3) specific control technologies affect multiple emissions, Oglethorpe cannot determine the aggregate effect of these or future regulations.

    Carbon Dioxide Emissions and Climate Change.    Efforts to limit emissions of carbon dioxide from power plants continue to increase. Laws that would limit such emissions could originate in Congress or existing laws could be applied as an outgrowth of ongoing litigation.

    Congress continues to consider legislation, including climate-change legislation, that would amend the Clean Air Act or other federal statutes, many versions of which may impose more stringent emissions limitations, including limits related to carbon dioxide emissions on power plants. Although there are many differences in these legislative proposals, most would impose caps on emissions of carbon dioxide at existing and future power plants that would increase in stringency over time. The impact of any federal legislation would depend upon the specific requirements enacted and cannot be determined at this time.

    Litigation related to carbon dioxide emissions continues on numerous fronts, and the outcome of such litigation could affect the power plants owned by Oglethorpe. In 2007, the U.S. Supreme Court ruled that certain greenhouse gases, including carbon dioxide, were pollutants which EPA has authority to regulate under the Clean Air Act, if it concludes regulation is needed to protect public health or welfare. The Court directed EPA to decide whether such regulation is needed, and EPA is now contemplating further action in response to the Court. In another case, in 2004, Attorneys General from eight states and the Corporation Counsel of New York filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaint alleges that the companies' emissions of carbon dioxide contribute to global warming, which the Plaintiffs claim is a public nuisance. In September 2005, the Court granted the defendants' motions to dismiss, which the plaintiffs appealed in October 2005. The matter is now awaiting decision in the U.S. Court of Appeals for the Second Circuit. In a companion case to the Supreme Court matter, state, municipal and private parties filed a petition for review of EPA's failure to adopt regulations governing power plant emissions of carbon dioxide and other greenhouse gases under the Clean Air Act. In issuing a new final rule establishing updated New Source Performance Standards ("NSPS") for steam generating units operated by electric utilities (and other industrial and commercial facilities), EPA took the position that it did not have the authority to set NSPS regulating these greenhouse gases under the Clean Air Act. EPA did not set a NSPS for carbon dioxide in the rule, relying on its findings prior to the Supreme Court case that it has no authority under the Clean Air Act to establish regulations that address climate change. Petitioners challenged the NSPS on numerous grounds, including that EPA should have set a standard for carbon dioxide. After the Supreme Court reached its decision discussed above, the D.C. Circuit remanded the case back to EPA in September 2007 for further proceedings in light of that decision. While the outcome of these matters cannot be determined at this time, adverse results in one or more of these cases could result in substantial capital expenditures and/or increased operating costs at Plants Wansley and/or Scherer.

    Other Relevant Litigation.    In November 1999, the United States Justice Department, on behalf of EPA, filed lawsuits against GPC and some of its affiliates, as well as other utilities. The lawsuits allege violations of the new source review provisions and the new source performance standards of the Clean Air Act at, among other facilities, Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named in the lawsuits and Oglethorpe does not have an ownership interest in the named units of Plant Scherer. However, Oglethorpe can give no assurance that units in which Oglethorpe has an ownership interest will not be affected by this or a related lawsuit in the future. The case has remained administratively closed since the spring of 2001. The resolution of this matter is highly uncertain at this time, as is any responsibility of Oglethorpe for a share of any penalties and capital costs required to remedy any violations at its co-owned facilities.

    In December 2002 and October 2003, EPA promulgated revisions to its new source review ("NSR") rule. Petitions to review both of these final rules were filed with the U.S. Court of Appeals for the District of Columbia Circuit. In June 2005, that Court

15

upheld the December 2002 rule in part. However, it also vacated certain portions of the rule, including those excluding pollution control projects from NSR. The October 2003 rule, which was intended to clarify the scope of the exclusion for routine maintenance and repair, was vacated by the court in March 2006. In October 2005, EPA also proposed a rule to clarify the test to be used for determining whether, following a change to a unit, an emissions increase would, for purposes of NSR, be deemed to occur. The impact of the litigation on the two final rules and the proposed rulemaking will depend on the ultimate resolution of these matters and the actions taken by the State of Georgia in response to them and cannot be predicted at this time.

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

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

Other Environmental Regulation

    Coal combustion waste disposed in landfills and surface impoundments is a regulated solid waste that is exempt from hazardous waste regulations. As part of a 2000 regulatory determination, EPA is developing national solid waste management standards to address coal combustion waste. Although coal combustion waste will continue to be classified as non-hazardous under the Resource Conservation and Recovery Act, the new standards will likely include increased groundwater monitoring, more stringent siting requirements and closure of existing coal waste management facilities not meeting minimum standards. Depending on the outcome of such rulemaking, which may occur in 2008, substantial additional costs for the management of these wastes might be required of Oglethorpe.

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

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

    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

16

the final legislation and the development of implementing regulations.

    Oglethorpe, or generating facilities in which Oglethorpe has an interest, are also subject, from time to time, to claims relating to operations and/or emissions, including actions by citizens to enforce environmental regulations and claims for personal injury due to such operations and/or emissions. Oglethorpe cannot predict the outcome of current or future actions, the responsibility of Oglethorpe for a share of any damages awarded or any impact on facility operations. Oglethorpe, however, does not believe that the current actions will have a material adverse effect on its financial position or results of operations.

Nuclear Regulation

    Oglethorpe is subject to the provisions of the Atomic Energy Act of 1954, as amended (the "Atomic Energy Act"), which vests jurisdiction in the 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 construction, operation and maintenance of nuclear power plants are regulated by the NRC. From time to time, new NRC regulations require changes in the design, operation and maintenance of existing nuclear reactors. Operating licenses issued by the NRC are subject to revocation, suspension or modification, and 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. An application to extend the licenses for each Unit at Plant Vogtle for an additional 20 years was submitted to the NRC in June 2007.

    An application has been filed with the NRC for an Early Site Permit that would allow the construction of two additional Units at Plant Vogtle. See "OGLETHORPE POWER CORPORATION – Future Power Resources" herein.

    Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the federal government has the responsibility for the final disposal of commercially produced high-level radioactive waste materials, including spent nuclear fuel. This Act requires the owner of nuclear facilities to enter into disposal contracts with the Department of Energy ("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. See Note 1 of Notes to Consolidated Financial Statements for information regarding the outcome of this litigation.

    Plants Hatch and Vogtle currently have on-site spent-fuel wet storage capacity and Plant Hatch has an on-site dry storage facility. The on-site dry storage facility for Plant Hatch became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant. Plant Vogtle's spent fuel pool storage is expected to be sufficient until 2015. 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 Consolidated Financial Statements.)

    For information concerning nuclear insurance, see Note 8 of Notes to Consolidated 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 Consolidated Financial Statements.

Federal Power Act

    Oglethorpe is subject to the provisions of the Federal Power Act applicable to licensees with respect to their hydroelectric developments. Rocky Mountain is a hydroelectric project subject to licensing by FERC.

    Oglethorpe has a license, expiring in 2027, for Rocky Mountain. See "PROPERTIES – Generating Facilities" for additional information.

    Upon or after the expiration of the license, the United States Government, by act of Congress, may

17

take over the project or FERC may relicense the project either to the original licensee or to a new licensee. In the event of takeover or relicensing to another, the original licensee is to be compensated in accordance with the provisions of the Federal Power Act, such compensation to reflect the net investment of the licensee in the project, not in excess of the fair value of the property taken, plus reasonable damages to other property of the licensee resulting from the severance therefrom of the property taken. If FERC does not act on the new license application prior to the expiration of the existing license, FERC is required to issue annual licenses, under the same terms and conditions of the existing license, until a new license is issued.

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

18

ITEM 1A. RISK FACTORS

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

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

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

    Generally, these environmental regulations are becoming increasingly stringent and may require Oglethorpe to change the design or operation of existing facilities or change or delay the location, design, construction or operation of new facilities. These changes, in turn, may result in substantial increases in the cost of electric service. Oglethorpe has in the past committed significant capital expenditures to achieve and maintain compliance with these regulatory requirements at its facilities, and Oglethorpe expects that it will make significant capital expenditures related to environmental compliance in the future.

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

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

    In addition, existing environmental laws and regulations may be revised or new laws and regulations seeking to protect the environment may be adopted or become applicable to Oglethorpe's facilities. Revised or additional laws and regulations, and in particular climate change legislation or regulations, could result in significant additional expense and operating restrictions on Oglethorpe's facilities or increased compliance costs which may result in significant increases in the cost of electric service. The cost impact of such legislation would depend upon the specific requirements enacted and cannot be determined at this time.

Oglethorpe owns nuclear facilities, which give rise to environmental, regulatory, financial and other risks, and may participate in the development of new nuclear facilities in the future.

    Oglethorpe owns a 30 percent undivided interest in Plant Hatch and Plant Vogtle, each of which is a two unit nuclear generating facility, and which collectively account for approximately 25 percent of Oglethorpe's generating capacity. Oglethorpe's ownership interest in these facilities exposes it to various risks, including:

•

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

•

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

•

potential liabilities arising out of nuclear incidents or terrorist attacks, including the payment of

19

respective insurance premiums, whether at its own plants or the plants of other nuclear owners; and

•

risks related to the expected costs, and financing thereof, of decommissioning these facilities at the end of their operational life.

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

    Oglethorpe maintains an internal fund and an external trust fund for the expected cost of decommissioning its nuclear facilities; however, it is possible that decommissioning costs and liabilities could exceed the amount of these funds. Additionally, Oglethorpe's nuclear units require licenses that, in some cases, need to be renewed or extended in order to continue operating beyond their initial forty-year terms. As a result of potential terrorist threats and increased public scrutiny, it may be more difficult or expensive to renew or extend these licenses.

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

    Oglethorpe is participating with the other co-owners of Plant Vogtle in the potential development of up to two additional nuclear units at the Plant Vogtle site. Oglethorpe has an option to participate in up to 30 percent of any new project and possibly more, under certain circumstances arising from reduced participation by other co-owners. The extent of Oglethorpe's ultimate involvement, if any, will be determined within the next year. Any participation by Oglethorpe in the development of new nuclear facilities could increase its exposure to the risks described above.

    In addition, the construction of large generating plants involves significant financial risk. Moreover, no nuclear plants have been constructed in the United States using advanced designs. Therefore, estimated cost of construction of any new nuclear plant is inherently uncertain. If Oglethorpe chooses to participate in the development of any new nuclear units, it could be exposed to the risk of cost uncertainty in connection with such projects.

Oglethorpe could be adversely affected if it is unable to continue to operate its facilities in a successful manner.

    The operation of Oglethorpe's generating facilities may be adversely impacted by various factors, including:

•

the risk of equipment failure or operator error;

•

operating limitations that may be imposed by regulatory requirements;

•

compliance with mandatory reliability standards;

•

labor disputes or shortages;

•

fuel or material supply interruptions;

•

terrorist attacks; or

•

catastrophic events such as fires, floods, explosions or similar occurrences.

    These or similar negative events could interrupt or limit electric generation or increase the cost of operating Oglethorpe's facilities, which could have the effect of increasing the cost of electric service provided by Oglethorpe to the Members.

Oglethorpe may incur significant costs related to ongoing capital expenditures at its existing generating facilities and for the potential construction or acquisition of new generating facilities.

    Oglethorpe's existing facilities require ongoing capital expenditures in order to maintain efficient and reliable operations. Many of Oglethorpe's facilities were constructed years ago, and as a result may require significant capital expenditures in order to maintain efficiency and reliability, and to comply with changing environmental requirements.

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    In addition, due to continued growth in their service territories, the Members may request that Oglethorpe expand its existing generating facilities or build or acquire new generating facilities, which would require significant capital expenditures. The completion of construction projects without delays or cost overruns is subject to substantial risks, including:

•

shortages and inconsistent quality of equipment, materials and labor;

•

work stoppages;

•

permits, approvals and other regulatory matters;

•

adverse weather conditions;

•

unforeseen engineering problems;

•

environmental and geological conditions;

•

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

•

unanticipated increases in the costs of materials and labor; and

•

attention to other projects.

    All of these risks could have the effect of increasing the cost of electric service provided by Oglethorpe to the Members.

Oglethorpe's ability to access capital could be adversely affected by various factors, including potential limitations on the availability of RUS loans.

    Oglethorpe relies on access to capital as a significant source of liquidity for capital requirements not satisfied by cash flow generated from operations. Historically, Oglethorpe and other electric generating cooperatives have relied on federal loan programs guaranteed by RUS in order to meet a significant portion of their long-term financing needs. However, the availability and magnitude of annual RUS funding levels are subject to the federal budget appropriations process, and therefore are subject to uncertainty because of periodic budgetary pressures faced by Congress. In addition, a new wave of generation construction nationwide among electric cooperatives is resulting in increased competition for available RUS funding levels. If the amount of RUS-guaranteed loan funds available to Oglethorpe in the future is decreased or eliminated, Oglethorpe may have to seek alternative sources of financing (see "OGLETHORPE POWER CORPORATION – Relationship with RUS").

    Therefore, in the future Oglethorpe's reliance on access to both short-term and long-term capital markets may become an increasingly important factor. Oglethorpe has successfully accessed the capital markets in the past, and believes that it will maintain sufficient access to capital markets based on current credit ratings. However, Oglethorpe's credit ratings reflect the views of the rating agencies, which could change at any point in the future. Oglethorpe's borrowing costs could increase and its potential pool of investors, funding sources and liquidity could decrease if its credit ratings were lowered, particularly below investment grade.

    In addition, certain market disruptions could constrain, at least temporarily, Oglethorpe's liquidity and ability to access capital on favorable terms or at all. Such disruptions include:

•

capital market conditions generally, including the current turmoil and uncertainty in the capital and credit markets;

•

an economic downturn;

•

the overall health of the energy industry;

•

negative events in the energy industry, such as a bankruptcy of an unrelated energy company;

•

increased scrutiny by lenders of the risks of construction of coal-fired power plants due to concerns over greenhouse gas emissions;

•

war or threat of war; or

•

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

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

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

    Oglethorpe's business model is to provide the Members with wholesale electric power at the lowest possible cost. Other technologies currently exist or are in development, such as fuel cells, microturbines, windmills and solar cells, that may in the future be

21

capable of producing electric power at costs that are comparable with, or lower than, Oglethorpe's cost of generating power. If these technologies were to develop sufficient economies of scale, the value of Oglethorpe's generating facilities could be adversely affected.

Changes in fuel prices could have an adverse effect on Oglethorpe's cost of electric service.

    Oglethorpe is exposed to the risk of changing prices for fuels, including coal, natural gas and uranium. Oglethorpe has taken steps to manage this exposure by entering into fixed or capped price contracts for some of its coal requirements. Oglethorpe has also entered into natural gas swap arrangements on behalf of some of its Members designed to manage the exposure of those Members to fluctuations in the price of natural gas. The operator of the nuclear plants owned by Oglethorpe manages price and supply risk through use of long term fixed or capped price contracts with multiple vendors of uranium ore mining, conversion and enrichment services. However, these arrangements do not cover all of Oglethorpe's and the Members' risk exposure to increases in the prices of fuels. Therefore, increases in fuel prices could significantly increase the cost of electric service provided by Oglethorpe to the Members.

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

    Oglethorpe obtains its fuel supplies, including coal, natural gas and nuclear, from a number of different suppliers. Any disruptions in Oglethorpe's fuel supplies, including disruptions due to weather, labor relations, environmental regulations, or other factors affecting Oglethorpe's fuel suppliers, could result in Oglethorpe having insufficient levels of fuel supplies. For example, rail transportation bottlenecks have from time to time caused transportation companies to be unable to perform their contractual obligations to deliver coal on a timely basis and have resulted in lower than normal coal inventories at certain of Oglethorpe's generating plants. Similar inventory shortages could occur in the future. Natural gas supplies can also be subject to disruption due to natural disasters and similar events. For example, hurricanes in the Gulf of Mexico during 2005 resulted in short-term limitations in the production and distribution of natural gas, resulting in shortages and significant increases in the price of natural gas. Any failure to maintain an adequate inventory of fuel supplies could require Oglethorpe to operate other generating plants at higher cost or require the Members to purchase higher-cost energy from other sources.

Future deregulation or restructuring of the electric industry in Georgia could subject the Members to increased competition and adversely affect their ability to satisfy their financial obligations to Oglethorpe.

    Under current Georgia law, Oglethorpe's Members generally have the exclusive right to provide retail electric service in their respective territories, subject to limited exceptions. Some states have implemented various forms of retail competition among power suppliers. While no such legislation has been enacted or is currently proposed in Georgia, there is no assurance that legislative, regulatory or other changes will not in the future lead to increased competition in the electric industry. If Oglethorpe and its Members are unable to adapt to any such changes, the prices they charge for electric service could become less competitive. While Oglethorpe provides electric service to the Members under long-term, take-or-pay contracts providing for joint and several liability among the Members, if one or more Members were to experience significant financial losses as a result of increased competition, the Members may have difficulty performing their obligations to Oglethorpe under their Wholesale Power Contracts.

Oglethorpe's ability to meet its financial obligations could be adversely affected if Members fail to perform their contractual obligations to Oglethorpe.

    Oglethorpe depends primarily on revenue from the Members under the Wholesale Power Contracts to meet its financial obligations. The Members are Oglethorpe's owners and Oglethorpe does not control their operations or financial performance. Further, Members must forecast their load growth and power supply needs. If Members acquire more power supply resources than needed, whether from Oglethorpe or other suppliers, or fail to acquire sufficient supplies, Members' rates could increase excessively and affect financial performance. Thus, Oglethorpe is exposed to the risk that one or more Members could default in the performance of their obligations to Oglethorpe under the Wholesale Power Contracts. Oglethorpe's ability to satisfy its financial obligations could be adversely affected if one or more of the Members, particularly one of the larger Members, defaulted on their payment obligations to Oglethorpe. Although the Wholesale Power Contracts obligate non-defaulting Members to pay the amounts of any payment default, pursuant to a pro rata step-up formula, there can be no guarantee that other Members would be able to fulfill this obligation.

ITEM 1B. UNRESOLVED STAFF COMMENTS

    None.

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ITEM 2. PROPERTIES

Generating Facilities

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

Facilities		Type of Fuel	Percentage Interest	Oglethorpe's Share of NamePlate Capacity (MW)		Commercial Operation Date	License Expiration Date
Plant Hatch (near Baxley, Ga.)
	Unit No. 1	Nuclear	30	243.0		1975	2034
	Unit No. 2	Nuclear	30	246.0		1979	2038
Plant Vogtle (near Waynesboro, Ga.)
	Unit No. 1	Nuclear	30	348.0		1987	2027	(1)
	Unit No. 2	Nuclear	30	348.0		1989	2029	(1)
Plant Wansley (near Carrollton, Ga.)
	Unit No. 1	Coal	30	259.5		1976	N/A	(2)
	Unit No. 2	Coal	30	259.5		1978	N/A	(2)
	Combustion Turbine	Oil	30	14.8		1980	N/A	(2)
Plant Scherer (near Forsyth, Ga.)
	Unit No. 1	Coal	60	490.8		1982	N/A	(2)
	Unit No. 2	Coal	60	490.8		1984	N/A	(2)
Rocky Mountain (near Rome, Ga.)		Pumped Storage Hydro	74.61	632.5		1995	2027
Doyle (near Monroe, Ga.)		Gas	100	325.0	(3)	2000	N/A	(2)
Talbot (near Columbus, Ga.)
	Units No. 1-4	Gas	100	412.0		2002	N/A	(2)
	Units No. 5-6	Gas-Oil	100	206.0		2003	N/A	(2)
Chattahoochee (near Carrollton, Ga.)		Gas	100	468.0		2003	N/A	(2)
Total				4,743.9

(1)

An application to extend these licenses for an additional 20 years was filed in June 2007.

(2)

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

(3)

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

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Plant Performance

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

		Equivalent Availability (1)						Capacity Factor (2)
Unit		2007		2006		2005		2007		2006		2005
Plant Hatch
	Unit No. 1	97	%	85	%	91	%	98	%	86	%	92	%
	Unit No. 2	87		98		86		87		99		87
Plant Vogtle
	Unit No. 1	100		85		90		101		86		91
	Unit No. 2	83		91		84		84		92		85
Plant Wansley
	Unit No. 1	83		98		89		77		88		78
	Unit No. 2	98		85		99		91		77		86
Plant Scherer
	Unit No. 1	86		90		97		80		80		88
	Unit No. 2	90		97		87		85		87		80
Rocky Mountain (3)
	Unit No. 1	86		91		91		22		24		26
	Unit No. 2	97		88		97		25		17		10
	Unit No. 3	37		78		89		6		16		21
Doyle (3)(4)		92		100		98		2		2		2
Talbot (3)		90		96		97		3		2		1
Chattahoochee		91		95		87		38		22		19

(1)

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

(2)

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

(3)

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

(4)

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

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

Fuel Supply

    Coal.    Coal for Plant Wansley is currently purchased under term contracts and in spot market transactions, primarily from coal mines in the eastern United States. As of February 29, 2008, Oglethorpe had a 53-day coal supply at Plant Wansley based on continuous operation.

    Coal for Scherer Units No. 1 and No. 2 is purchased under term contracts and in spot market transactions. As of February 29, 2008, Oglethorpe's coal stockpile at Plant Scherer contained a 70-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming.

    Oglethorpe separately dispatches Plant Wansley and Plant Scherer, but uses GPC as its agent for fuel procurement. Oglethorpe currently leases approximately 1,200 rail cars to transport coal to these two facilities.

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

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

    Natural Gas.    Oglethorpe purchases the natural gas, including transportation and other related services, needed to operate Doyle, Talbot and Chattahoochee and the combustion turbines owned by Hartwell Energy Limited Partnership. Oglethorpe purchases natural gas in the spot market and under agreements at indexed prices. Oglethorpe has entered into hedge agreements to manage a portion of its exposure to fluctuations in the market price of natural gas. Oglethorpe manages exposure to such risks only with respect to Members that elect to receive such services. Oglethorpe purchases transportation under long-term firm and short-term firm and non-firm contracts. Oglethorpe has also purchased a limited amount of storage capacity in a storage cavern that is under construction, with an expected in-service date of mid-2008. (See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Commodity Price Risk.")

24

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.

	Nuclear Plant Hatch		Plant Vogtle		Coal-Fired Plant Wansley		Scherer Units No. 1 & No. 2		Pumped Storage Rocky Mountain		Total
	%	MW (1)	%	MW (1)	%	MW (1)	%	MW (1)	%	MW (1)	MW (1)
Oglethorpe	30.0	489	30.0	696	30.0	519	60.0	982	74.61	633	3,319
GPC	50.1	817	45.7	1,060	53.5	926	8.4	137	25.39	215	3,155
MEAG	17.7	288	22.7	527	15.1	261	30.2	494	–	–	1,570
Dalton	2.2	36	1.6	37	1.4	24	1.4	23	–	–	120
Total	100.0	1,630	100.0	2,320	100.0	1,730	100.0	1,636	100.00	848	8,164

(1)

Based on nameplate ratings.

Georgia Power Company

    GPC is a wholly owned subsidiary of The Southern Company and is engaged primarily in the generation and purchase of electric energy and the transmission, distribution and sale of 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 some of Oglethorpe's Members, MEAG and two municipalities. GPC is the largest supplier of electric energy in the State of Georgia. (See "BUSINESS – Oglethorpe Power Corporation – Relationship with GPC.") GPC is subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and, in accordance therewith, files reports and other information with the Securities and Exchange Commission ("SEC").

Municipal Electric Authority of Georgia

    The Municipal Electric Authority of Georgia (known as MEAG Power) is a state-chartered, municipal joint-action agency that provides capacity and energy to its membership of 49 municipal electric utilities (including 48 cities and one county in the State of Georgia). MEAG Power has wholesale take-or-pay power sales contracts with each of its 49 participants that extend to June 2054. The participants are located in 39 of the State's 159 counties and collectively serve approximately 300,000 electric consumers (meters). MEAG Power is the state's third largest power supplier behind Oglethorpe.

City of Dalton, Georgia

    Dalton Utilities is a combined utility that provides electric, gas, water and wastewater services to the city of Dalton (located in northwest Georgia) and some of the surrounding communities. It presently serves more than 10,000 residential, commercial and industrial electric customers.

The Plant Agreements

Hatch, Wansley, Vogtle and Scherer

    Oglethorpe's rights and obligations with respect to Plants Hatch, Wansley, Vogtle and Scherer are contained in a number of contracts between Oglethorpe and GPC and, in some instances, MEAG and Dalton. Oglethorpe is a party to four Purchase and Ownership Participation Agreements ("Ownership Agreements") under which it acquired from GPC a 30 percent undivided interest in each of Plants Hatch, Wansley and Vogtle, a 60 percent undivided interest in Scherer Units No. 1 and No. 2 and a 30 percent undivided interest in those facilities at Plant Scherer intended to be used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the "Scherer Common Facilities"). Oglethorpe has also entered into four Operating Agreements ("Operating Agreements") relating to the operation and maintenance of Plants Hatch, Wansley, Vogtle and Scherer, respectively. The Ownership Agreements and Operating Agreements relating to Plants Hatch and Wansley are two-party agreements between Oglethorpe and GPC. The Ownership Agreements and Operating Agreements relating to Plants Vogtle and Scherer are agreements among Oglethorpe, GPC, MEAG and Dalton. The parties to each Ownership Agreement and Operating

25

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

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

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

    Under the Ownership Agreements, Oglethorpe is obligated to pay a percentage of capital costs of the respective plants, as incurred, equal to the percentage interest which it owns or leases at each plant. GPC has responsibility for budgeting capital expenditures for Scherer Units No. 1 and 2 subject to certain limited rights of the participants to disapprove capital budgets proposed by GPC and to substitute alternative capital budgets. GPC has responsibility for budgeting capital expenditures for Plants Hatch and Vogtle, subject to the right of any co-owner to disapprove large discretionary capital improvements.

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

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

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

26

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 substitute alternative budgets. The Ownership Agreements and Operating Agreements provide that, should a participant fail to make any payment when due, among other things, such nonpaying participant's rights to output of capacity and energy would be suspended.

    The Operating Agreement for Plant Hatch will remain in effect with respect to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. Oglethorpe has entered into an agreement with GPC, subject to RUS approval, to extend the Operating Agreement for so long as an NRC operating license exists for each unit. (See "BUSINESS – ENVIRONMENTAL AND OTHER REGULATION – Nuclear Regulation.") The Operating Agreement for Plant Vogtle will remain in effect with respect to each unit at Plant Vogtle until 2018. The Operating Agreement for Plant Wansley will remain in effect with respect to Plant Wansley Units No. 1 and No. 2 until 2016 and 2018, respectively. The Operating Agreement for Scherer Units No. 1 and No. 2 will remain in effect with respect to Scherer Units No. 1 and No. 2 until 2022 and 2024, respectively. Upon termination of each Operating Agreement, following any extension agreed to by the parties, GPC will retain such powers as are necessary in connection with the disposition of the property of the applicable plant, and the rights and obligations of the parties shall continue with respect to actions and expenses taken or incurred in connection with such disposition.

    In conjunction with the potential development of additional units at Plant Vogtle (see "BUSINESS – OGLETHORPE'S POWER SUPPLY RESOURCES – Future Power Resources"), the co-owners have entered into amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, and have entered into an Ownership Agreement that would govern participation in Vogtle Units No. 3 and No. 4, if any.

Rocky Mountain

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

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

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

    In late 1996 and early 1997, Oglethorpe completed lease transactions for its 74.61 percent undivided ownership interest in Rocky Mountain. 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. For more information about the structure of these lease transactions, see "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Financial Condition – Off-Balance Sheet Arrangements – Rocky Mountain Lease Transactions."

Doyle

    Oglethorpe has an agreement with Doyle I LLC, a limited liability company owned by one of Oglethorpe's

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Members, Walton EMC, to purchase the output of a gas-fired combustion turbine generating facility with a nominal contract rating of 325 MW over a 15-year term. Delivery commenced May 15, 2000.

    During the term of the agreement, Oglethorpe has the right and obligation to purchase all of the capacity and energy from the facility. Oglethorpe is obligated to pay to Doyle I, LLC each month a capacity charge based on a performance rating and an energy charge equal to all costs of operating the facility. Oglethorpe is also obligated to pay the actual operation and maintenance costs and the costs of capital improvements. Oglethorpe is responsible for supplying all natural gas necessary to operate the facility. Oglethorpe has the right to dispatch the facility.

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

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

ITEM 3. LEGAL PROCEEDINGS

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

    For information about environmental matters that could have an effect on Oglethorpe, see Note 12 of Notes to Consolidated 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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

    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, 2007, have been derived from the audited financial statements of Oglethorpe. This data should be read in conjunction with "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" and the "FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA."

				(dollars in thousands)
				2007			2006			2005			2004			2003
Operating revenues:
	Sales to Members		$	1,149,657		$	1,127,423		$	1,136,463		$	1,279,465		$	1,167,605
	Sales to non-Members			1,585			1,456			33,060			33,307			35,948
Total operating revenues				1,151,242			1,128,879			1,169,523			1,312,772			1,203,553
Operating expenses:
	Fuel			415,125			374,144			365,073			290,106			234,172
	Production			246,675			254,658			251,830			248,084			253,865
	Purchased power			155,005			179,129			255,616			402,941			359,447
	Depreciation and amortization			131,908			157,303			153,030			153,126			141,301
	Accretion			19,326			21,932			33,996			20,456			7,815
	Income taxes			–			–			–			(3	)		(459	)
	Gain on sale of emission allowances			(394	)		(39,529	)		(83,098	)		–			–
Total operating expenses				967,645			947,637			976,447			1,114,710			996,141
Operating margin				183,597			181,242			193,076			198,062			207,412
Other income, net				58,485			56,469			45,123			42,228			32,737
Net interest charges				(223,021	)		(219,510	)		(220,546	)		(223,053	)		(223,300	)
Net margin			$	19,061		$	18,201		$	17,653		$	17,237		$	16,849
Electric plant, net:
	In service		$	3,161,954		$	3,274,080		$	3,427,101		$	3,547,337		$	3,665,991
	Nuclear fuel, at amortized cost			130,138			119,076			94,159			87,941			90,283
	Construction work in progress			189,102			68,145			26,721			22,830			26,212
Total electric plant			$	3,481,194		$	3,461,301		$	3,547,981		$	3,658,108		$	3,782,486
Total assets			$	4,937,320		$	4,901,745		$	4,826,916		$	4,813,042		$	4,948,117
Capitalization:
	Long-term debt		$	3,409,038		$	3,402,094		$	3,238,648		$	3,351,664		$	3,534,185
	Obligations under capital leases			286,729			313,821			332,434			344,412			360,697
	Obligation under Rocky Mountain transactions			101,272			94,772			88,689			83,012			77,684
	Patronage capital and membership fees			516,570			497,509			479,308			461,655			444,418
	Accumulated other comprehensive loss			(32,691	)		(28,988	)		(35,498	)		(46,760	)		(50,534	)
	Subtotal			4,280,918			4,279,208			4,103,581			4,193,983			4,366,450
		Less: long-term debt and capital leases due within one year		(143,400	)		(234,621	)		(217,743	)		(190,835	)		(237,522	)
Total capitalization			$	4,137,518		$	4,044,587		$	3,885,838		$	4,003,148		$	4,128,928
Property additions			$	194,739		$	134,518		$	69,744		$	76,531		$	166,674
Energy supply (megawatt-hours):
	Generated			21,577,805			21,272,913			20,962,600			21,035,609			18,956,147
	Purchased			1,593,864			2,108,654			3,812,809			11,167,140			10,888,883
	Available for sale			23,171,669			23,381,567			24,775,409			32,202,749			29,845,030
Member revenues per kWh sold				5.04¢			4.90¢			4.79¢			4.10¢			4.00¢

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

Forward-Looking Statements and Associated Risks

    This Annual Report on Form 10-K contains forward-looking statements, including statements regarding, among other items, (i) anticipated trends in the business of Oglethorpe, (ii) Oglethorpe's future power supply requirements, resources and arrangements, (iii) Oglethorpe's expected future capital expenditures and (iv) disclosures regarding market risk included in "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK." Some forward-looking statements can be identified by use of terms such as "may," "will," "expects," "anticipates," "believes," "intends," "projects," "plans" or similar terms. These forward-looking statements are based largely on Oglethorpe's current expectations and are subject to a number of risks and uncertainties, some of which are beyond Oglethorpe's control. For some of the factors that could cause actual results to differ materially from those anticipated by these forward-looking statements, see "RISK FACTORS." 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 on Form 10-K will in fact transpire.

Executive Overview

    Oglethorpe is a not-for-profit electric cooperative whose principal business is providing wholesale electric service to 38 Members. Consequently, substantially all of Oglethorpe's revenues and cash flow is derived from sales to the Members pursuant to long-term, take-or-pay wholesale power contracts. These contracts obligate the Members jointly and severally to pay all of Oglethorpe's costs and expenses associated with owning and operating its power supply business. To that end, Oglethorpe's existing rate structure provides for a pass-through of actual energy costs. Charges for fixed costs (including capacity, other non-energy charges, debt service obligations and the margin required to meet Oglethorpe's Margins for Interest Ratio rate covenant) are carefully managed throughout the year to ensure that sufficient capacity-related revenues are produced. This rate structure provides Oglethorpe with the ability to manage its revenues to assure full recovery of its costs in rates and has resulted in a consistent record of meeting all of its financial requirements. The year 2007 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.

    In 2005, each of Oglethorpe's Members extended the base term of their wholesale power contract with Oglethorpe by 25 years to 2050. This term is sufficient to cover the projected remaining useful lives of all of Oglethorpe's assets. In connection with the contract extension, Oglethorpe undertook a systematic program to refinance or otherwise reamortize a portion of its long-term debt to better match the principal amortization of debt to the projected useful lives of its assets. Significant progress on this program occurred in 2006 and 2007, and this initiative should be substantially completed by the end of 2008.

    Throughout 2007, Oglethorpe continued to maintain a strong liquidity position that is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and a commercial paper program. Unrestricted available liquidity at year-end was $841 million.

    Although Members have had the option to acquire resources from other suppliers since 1997, in 2003, Oglethorpe entered into amended agreements with its Members giving the Members direct responsibility for the planning and procurement of their future power supply requirements. Under these member agreements, Oglethorpe is limited in its ability to develop or obtain new power supply resources to assist the Members with their future, incremental power requirements without the approval of a substantial majority of the Members. This is particularly relevant since the Members have had to plan and implement power supply options to replace a portion of the energy that was being provided by two significant power marketer agreements that terminated in 2004 and 2005. While Oglethorpe resources (generating facilities and power purchase contracts) had historically provided more than 90 percent of the Members' requirements, as a result of the terminations of these power marketer agreements, energy supplied by Oglethorpe now accounts for a smaller percentage of the Members' requirements. In 2007, energy supplied by Oglethorpe accounted for approximately 63 percent of the Members' retail energy requirements.

    From time to time, Oglethorpe may assist the Members in investigating potential new power supply

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resources. In the latter part of 2006, Oglethorpe and its Members initiated a more formal evaluation of the potential resources that might be required to meet the Members' power supply requirements in the 2011-2020 time period. Throughout 2007, Oglethorpe's efforts in this regard focused primarily on developing a menu of generation options that offers Members more ownership and control over their generation resources (through Oglethorpe) in order to help mitigate reliance on third-party contracts. Consequently, since this initiative began in 2006, Oglethorpe's efforts to evaluate potential power supply acquisitions, development, or contracting opportunities for future generation needs of the Members have increased significantly. Oglethorpe is also taking steps to financially prepare for these potential opportunities.

    Oglethorpe and the Members remain very interested in the potential development and deployment of the next generation of nuclear facilities and are therefore considering participation in any initiatives that will examine the feasibility of future nuclear generating facilities with the view of preserving the option to participate in any new nuclear generation that might be developed in Georgia. Accordingly, in May 2005 Oglethorpe and the other co-owners of nuclear Plant Vogtle executed an agreement regarding exploration of development of up to two additional nuclear units at the Plant Vogtle site. Oglethorpe has the option to participate in up to 30 percent of any new units. The extent of Oglethorpe's ultimate involvement, if any, is expected to be determined during the next year.

    Oglethorpe continues to respond to changing environmental requirements. Over the past several years, Oglethorpe has invested approximately $230 million at its coal-fired generating facilities to maintain compliance with various environmental regulations. These expenditures include projects related to the installation of selective catalytic reduction control technologies and flue gas desulfurization systems at Plant Wansley, the conversion of Plant Scherer to permit it to burn Powder River Basin coal, and initial activities associated with the installation of mercury controls, selective catalytic reduction control technologies and flue gas desulfurization systems at Plant Scherer. Completion of these projects by the end of 2014 (except the conversion of Plant Scherer to burn Powder River Basin coal, which was completed in 2003) is anticipated to cost approximately $900 million.

    One of the most significant risks 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 potential climate change legislation and regulations. While estimates of potential impacts can vary widely, it is not unlikely that Oglethorpe may incur significant additional costs over the next 10 to 20 years in response to this issue.

    From an operational perspective, Oglethorpe remains focused on the challenge of providing reliable, cost-effective fuel supply for its generating facilities. A balanced diversity of generating resources by fuel type – nuclear, coal and natural gas – helps mitigate the risk associated with any one type of fuel. The geographic diversity of coal supply – eastern and western (Powder River Basin) – as well as the diversity of suppliers helps reduce risks associated with coal. Due to rail transportation issues, timely and cost-effective transportation of coal was a high priority for the corporation in 2006, with inventories returning to normal levels throughout 2007. Oglethorpe will continue to maintain a focus on fuel strategies as the cost of fuel, higher or lower, directly impacts the cost of power to its Members.

    Additionally, there are certain risks inherent in Oglethorpe's undivided ownership interests in its two nuclear facilities, Plants Hatch and Vogtle. One such risk is the storage of spent fuel. While the progress towards a national repository is disappointing, both 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, which are capable of further expansion. Another risk unique to nuclear facilities is funding for the expected cost of decommissioning when the plants are retired. Oglethorpe continues to maintain adequate balances in its external trust fund for this purpose based on recent specific site studies, NRC minimum funding requirements and assumptions regarding investment earnings. With respect to operational risk, both plants continued an excellent record of operations in 2007.

    Despite the many challenges and risks of operating an electric power supply corporation, Oglethorpe continues to be well positioned, both financially and operationally, to fulfill its obligations to the Members and third parties.

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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. 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 percentage capacity responsibilities in the respective resources. Since its formation in 1974, Oglethorpe has generated a positive net margin in each year and had a balance of $517 million in patronage capital as of December 31, 2007. Oglethorpe's equity ratio, calculated as patronage capital and membership fees divided by total capitalization was 12.3 percent at December 31, 2007 and at December 31, 2006.

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

Rates and Regulation

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

    The rate schedule under the Wholesale Power Contracts implements on a long-term basis the assignment to each Member of responsibility for Oglethorpe's 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 distribution from such affiliate or subsidiary or if Oglethorpe has made a payment with respect to such losses or expenditures.

    The rate schedule also includes a prior period adjustment mechanism designed to ensure that Oglethorpe achieves the minimum 1.10 Margins for Interest Ratio. Amounts, if any, by which Oglethorpe fails to achieve a minimum 1.10 Margins for Interest Ratio would be accrued as of December 31 of the applicable year and collected from the Members during the period April through December of the following year. The rate schedule formula is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses recorded by Oglethorpe, plus amounts necessary to achieve at least the minimum 1.10 Margins for Interest Ratio.

    For 2007, 2006 and 2005, Oglethorpe achieved a Margins for Interest Ratio of 1.10.

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

Accounting Policies

Basis of Accounting

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

Critical Accounting Policy

    Oglethorpe has determined that the following accounting policy is important to understanding the presentation of Oglethorpe's financial condition and results of operations and requires Oglethorpe's management to make estimates and assumptions about matters that were uncertain at the time of preparation of Oglethorpe's financial statements. Changes in these estimates and assumptions by Oglethorpe's management could materially impact its results of operations and financial condition. Oglethorpe's management has discussed the development, selection and disclosure of critical accounting policies and estimates with the Audit Committee of Oglethorpe's Board of Directors.

    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, 2007, Oglethorpe's regulatory assets and liabilities totaled $278 million and $121 million, respectively. (See Note 1 of Notes to Consolidated Financial Statements.) While Oglethorpe does not currently foresee any event such as competitive or other factors that would make it not probable that Oglethorpe will recover these costs from its Members as future revenues through rates under its Wholesale Power Contracts, if such an event were to occur, Oglethorpe could no longer apply the provisions of SFAS No. 71, which would require Oglethorpe to eliminate all regulatory assets and liabilities that had been recognized as a charge to its statement of operations and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, Oglethorpe would be required to determine any impairment to other assets, including plants, and write-down those assets, if impaired, to their fair value.

New Accounting Pronouncements

    In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51." The Statement establishes accounting and reporting standards that require: a) ownership interests in subsidiaries be clearly identified and presented in consolidated statement of financial position within equity but separate from parent's equity; b) amount of consolidated net income attributable to parent and noncontrolling interest be present on face of consolidated statement of income; c) changes in parent's ownership interest while controlling financial interest in subsidiary is consistently accounted for; d) retained noncontrolling equity investment in deconsolidated subsidiary be initially measured at fair value; e) sufficient disclosure clearly identifies and distinguish between interests of parent and noncontrolling owners. SFAS No. 160 is effective for Oglethorpe January 1, 2009. Currently, the adoption of SFAS No. 160 is not expected to have any material impact on Oglethorpe's results of operations or financial condition.

    In December 2007, the FASB issued SFAS No. 141 (revised 2007), "Business Combinations." The Statement establishes principles and requirements for how the acquirer in a business combination: a) recognizes and measures the identifiable assets acquired, liabilities assumed, and noncontrolling interest in acquiree; b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; c) determines what information to disclose to enable users of financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141 (revised 2007) is effective for Oglethorpe January 1, 2009. Currently, the adoption of SFAS No. 141 (revised 2007) is not expected to have any material impact on Oglethorpe's results of operations or financial condition.

    In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities," including an amendment of SFAS

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No. 115, "Accounting for Certain Investments in Debt and Equity Securities." This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. This statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. The statement provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of this Statement apply only to entities that elect the fair value option however, the amendment to SFAS No. 115 applies to all entities with available-for-sale and trading securities. SFAS No. 159 is effective for Oglethorpe January 1, 2008. Oglethorpe will not elect the fair value option for any of its assets, except for assets accounted for under SFAS No. 115.

    In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles ("GAAP"), and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, the application of SFAS No. 157 may change the current practice for measuring fair value. Oglethorpe adopted SFAS No. 157 effective January 1, 2008 with no material effect on its results of operations or financial condition.

Results of Operations

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 the 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 2.0 percent for 2007 compared to 2006 and decreased by 0.8 percent for 2006 compared to 2005. The components of Member revenues were as follows:

		(dollars in thousands)
		2007		2006		2005
Capacity revenues	$	559,873	$	568,425	$	552,264
Energy revenues		589,784		558,998		584,199
Total	$	1,149,657	$	1,127,423	$	1,136,463

    Capacity revenues from Members decreased 1.5 percent in 2007 compared to 2006 and increased 2.9 percent in 2006 compared to 2005. For 2007, capacity revenues reflect lower collections from Members of $36.8 million related to lower Plant Vogtle depreciation and amortization expense and the reversal of the Monroe County property tax litigation reserve. For further discussion regarding depreciation and amortization, see "Operating Expenses" below and see Note 13 of Notes to Consolidated Financial Statements for further information regarding the Monroe County property tax litigation reserve reversal. In addition, capacity revenues for 2007 compared to 2006 were reduced by $5.1 million due to expiration of the GPC purchased power agreement effective March 31, 2006. For 2006 and 2005, capacity revenues reflect reduced collections from Members of $29.3 million and $61.9 million, respectively. Both the 2006 and 2005 reduced revenue collections were related to gains on the sale of SO₂ allowances. See Note 10 of Notes to Consolidated Financial Statements for further discussion regarding the sale of SO₂ allowances. In addition, capacity revenues for 2006 compared to 2005 were also reduced by $15.2 million due to the expiration of the GPC purchased power agreement.

    Energy revenues from Members increased 5.5 percent in 2007 compared to 2006 and decreased 4.3 percent in 2006 compared to 2005. Energy revenues increased in 2007 as compared to 2006 partly due to higher fuel costs and partly due to higher variable operation and maintenance (O&M) costs, offset somewhat by the pass through to Members of lower purchased power energy costs. See "Operating Expenses" below for further discussion for the changes in fuel costs, variable O&M and purchased power energy costs. The decrease in energy revenues for 2006 as compared to 2005 was due partly to the discontinuation of Oglethorpe's capacity and energy pool, effective March 31, 2005, and partly to the expiration of the GPC purchased power agreement, offset somewhat by an increase in fuel costs passed through to Members due primarily to an increase in generation.

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

	(in thousands) Kilowatt-hours	Cents per Kilowatt-hour
2007	22,815,174	5.04
2006	23,019,482	4.90
2005	23,721,939	4.79

    In 2007 and 2006, kWh sales to Members decreased 0.9 percent and 3.0 percent as compared to the same prior year periods, respectively. The average revenue per kWh from sales to Members increased 2.9 percent for 2007 compared to 2006 and increased 2.2 percent for 2006 compared to 2005. The expiration of an agreement to purchase capacity and energy from GPC was the primary reason for the decrease in MWhs sold to Members in 2007. The decrease in kWh sales to Members in 2006 was partly due to the discontinuation of Oglethorpe's capacity and energy pool, through which Oglethorpe bought and sold short-term energy from/to non-Members for the benefit of Members participating in the pool. The capacity and energy pool was discontinued effective March 31, 2005. The expiration of the GPC purchased power agreement also contributed to the decrease in MWhs sold to Members. For further discussion regarding purchased power costs, see "Operating Expenses" below.

    The energy portion of Member revenues per kWh increased 6.5 percent in 2007 as compared to 2006 and decreased 1.4 percent in 2006 compared to 2005. Oglethorpe passes through actual energy costs to the Members such that energy revenues equal energy costs. The increase in average energy revenues per kWh in 2007 compared to 2006 is primarily due to the pass through of higher fuel costs and higher variable O&M expenses. For further discussion regarding fuel costs and variable O&M expenses, see "Operating Expenses" below. The decrease in average energy revenues per kWh in 2006 as compared to 2005 resulted primarily from the reduction in the pass through of purchased power costs due to the discontinuation of the capacity and energy pool and the expiration of the GPC agreement as discussed above.

    Sales to Non-Members.    For 2007 and 2006, sales to non-Members resulted primarily from services provided to Oglethorpe's former Member Flint EMC. In 2005, sales to non-Members were primarily from capacity and energy sales to Alabama Electric Cooperative under an agreement to sell 100 MW of capacity for the period June 1998 through December 2005. In addition, Oglethorpe sold short-term energy to non-Members for the benefit of Members participating in its capacity and energy pool. The capacity and energy pool was discontinued effective March 31, 2005. Total non-Member revenues for 2007, 2006 and 2005 were $1,585,000, $1,456,000 and $33,060,000, respectively.

Operating Expenses

    Oglethorpe's operating expenses (excluding the 2007 and 2006 gains related to the sale of SO₂ allowances of $0.4 million and $39.5 million, respectively) decreased 2.0 percent in 2007 compared to 2006 and were 6.8 percent lower in 2006 compared to 2005. For 2007, decreases in production, and depreciation and amortization expenses offset somewhat by an increase in fuel costs were the primary drivers for the decrease in operating expenses. The decrease in operating expenses in 2006 as compared to 2005 was partly due to decreases in purchased power and accretion expenses offset somewhat by an increase in fuel costs.

    Total fuel costs increased 11.0 percent in 2007 compared to 2006 and increased 2.5 percent in 2006 as compared to 2005 while total generation increased 0.8 percent and 1.5 percent, respectively. Average fuel cost per MWh increased 10.0 percent in 2007 compared to 2006 and 1.0 percent in 2006 compared to 2005. For 2007 the increase in total and average fuel cost resulted primarily from a change in the mix of generation with increased generation of 572,000 MWhs or, 49.7 percent, from higher priced gas-fired facilities offset somewhat by lower generation from coal-fired facilities which has a lower average price than gas-fired generation. For 2006, the increase in total fuel cost was primarily due to the 1.5 percent increase in generation.

    Production expenses decreased 3.1 percent in 2007 compared to 2006 and increased 1.2 percent in 2006 as compared to 2005. The decrease in production expenses in 2007 primarily resulted from the reversal of the Monroe County property tax litigation reserve ($22.5 million) due a favorable ruling from the Georgia Supreme Court as discussed in Note 13 of Notes to Consolidated Financial Statements. This decrease was offset somewhat by higher variable O&M expenses resulting primarily from increased amortization for deferred nuclear refueling outage costs and for deferred outage costs associated with fossil fuel facilities. The increase in nuclear refueling outage amortization

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resulted partly from higher outage costs (and thus higher amortization) at Plant Vogtle due to an NRC mandated pressurized weld overlay project and partly due to an increase in outage costs at Hatch Unit No. 1 due to transformer replacement expenses. The increase in fossil fuel facilities primarily resulted from the deferral of such costs effective 2006. As a result, 2007 amortization reflected outage costs for both units at Plant Scherer and Plant Wansley while 2006 amortization reflected outage costs only for Plant Scherer Unit No. 1 and Wansley Unit No. 2.

    Purchased power costs decreased 13.5 percent in 2007 as compared to 2006 and decreased 29.9 percent in 2006 compared to 2005 as follows:

		(dollars in thousands)
		2007		2006		2005
Capacity costs	$	41,437	$	46,259	$	60,683
Energy costs		113,568		132,870		194,933
Total	$	155,005	$	179,129	$	255,616

    The decrease in purchased power capacity costs for 2007 compared to 2006 and for 2006 compared to 2005 was due to the expiration of the GPC purchased power agreement effective March 31, 2006 as discussed previously.

    Purchased power energy costs decreased 14.5 percent in 2007 compared to 2006 and decreased 31.8 percent in 2006 compared to 2005. Purchased MWhs decreased 24.4 percent for 2007 compared to 2006 and 44.7 percent in 2006 compared to 2005. The average cost of purchased power energy per kWh increased 13.1 percent in 2007 compared to 2006 and increased 23.8 percent in 2006 compared to 2005. The decrease in purchased power energy costs for 2007 compared to 2006 resulted primarily from the decrease in MWhs, which in turn resulted partly from the termination of the GPC agreement, effective March 31, 2006. The expiration of the GPC purchased power agreement with its favorable energy cost to Oglethorpe was primarily the reason for the increase in average energy cost per kWh. The decrease in MWhs acquired under Oglethorpe's energy replacement program which replaces power from Oglethorpe owned generation facilities with lower price spot market purchased power energy also contributed to the decrease in purchased power energy costs and to the volume of purchased power MWhs. The decrease in MWhs and energy costs from these sources was offset somewhat by an increase in MWhs and energy cost acquired under several purchased power agreements. The decrease in purchased power energy costs for 2006 compared to 2005 was partly due to the discontinuation of Oglethorpe's capacity and energy pool, effective March 31, 2005, and partly due to the expiration of the GPC purchased power agreement.

    Purchased power expenses for the years 2005 through 2007 include the cost of capacity and energy purchases under various long-term power purchase agreements. Oglethorpe's capacity and energy expenses under these agreements amounted to approximately $89 million in 2007, $103 million in 2006 and $163 million in 2005. For a discussion of the power purchase agreements, see Note 9 of Notes to Consolidated Financial Statements.

    Depreciation and amortization expense decreased 16.1 percent in 2007 compared to 2006 and increased 2.8 percent in 2006 as compared to 2005. The decrease in depreciation and amortization expense for 2007 is partly attributable to lower depreciation expenses for Plant Vogtle of $14.3 million. In June 2007, GPC, as agents for the co-owners, filed an application with the NRC to extend the licenses for Vogtle Unit No. 1 and Unit No. 2 for an additional 20 years. Effective July 1, 2007, Oglethorpe under the provisions of SFAS No. 71 began deferring the difference between Plant Vogtle depreciation expense based on the current 40-year operating license versus depreciation expense based on the applied for 20-year license extension. The deferral amount will be amortized in to deprecation expense over the remaining life of Plant Vogtle beginning in the year that the license extension is approved by the NRC. The approval from the NRC is expected mid-2009 or later. In addition, the lower depreciation and amortization expense in 2007 compared to 2006 resulted from $10.2 million in accelerated amortization of deferred amortization of capital leases as discussed below in accretion expense. This increase was offset somewhat by lower depreciation expenses for nuclear and coal-fired facilities due to adoption of lower composite depreciation rates effective January 1, 2006, approved by RUS and supported by a depreciation study performed in 2005.

    Accretion expense represents the change in the asset retirement obligations due to the passage of time. For nuclear decommissioning, Oglethorpe records a regulatory asset or liability for the timing difference in accretion expense recognized under SFAS No. 143, "Accounting for Asset Retirement Obligations,"

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compared to the expense recovered for ratemaking purposes. The accretion expense recognized is equal to the lesser of earnings from both the decommissioning trust fund and the internal decommissioning fund or the asset retirement obligations for nuclear decommissioning expenses to be recognized under SFAS No. 143. Accretion expense totaled $19.3 million in 2007, $21.9 million in 2006 and $34.0 million in 2005. The higher accretion expense in 2005 is primarily due to the increased amortization of deferred asset retirement costs per approval by the Board of Directors. During 2007, Oglethorpe sold SO₂ allowances in excess of its needs to various parties and received $0.4 million. During 2006, Oglethorpe sold SO₂ allowances in excess of its needs to various parties and received approximately $39.5 million in net proceeds from these sales. The proceeds received from sale of SO₂ allowances was offset, however, by a $29.3 million reduction in Sales to Members and by $10.2 million in accelerated amortization of deferred amortization of capital leases in 2006. During 2005, Oglethorpe sold SO₂ allowances in excess of its needs to various parties and received approximately $83.1 million in net proceeds from these sales. This gain on sale of SO₂ allowances was offset, however, by a $61.9 million reduction in Sales to Members and by $21.2 million in accelerated amortization of deferred asset retirement costs in the form of accretion expense. As a result, there was no change to net margin for 2006 and 2005 from the gains on sales of SO₂ allowances.

Other Income (Expense)

    Investment income increased 1 percent in 2007 compared to 2006 and increased 28.4 percent in 2006 compared to 2005. The increase in 2006 compared to 2005 was due to higher earnings from Oglethorpe's decommissioning trust fund and from higher interest earnings on cash and cash equivalent investments. The higher earnings on cash and cash equivalents were partly due to higher returns on these investments and partly due to a higher average investment balance. These increases were offset somewhat by lower earnings on funds deposited in the RUS Cushion of Credit Account resulting from a lower average investment balance. At December 31, 2006, there were no remaining deposits invested in the RUS Cushion of Credit Account.

Net Margin

    Oglethorpe's net margin for 2007, 2006 and 2005 was $19.1 million, $18.2 million and $17.7 million, respectively. These amounts were exactly sufficient to meet the 1.10 Margins for Interest requirement under the Mortgage Indenture. Oglethorpe's margin requirement is based on a ratio applied to interest charges. In addition, Oglethorpe's margins include certain items that are excluded from the Margins for Interest Ratio, such as non-cash capital credits allocation from GTC. Oglethorpe's non-cash capital credits allocation from GTC was $1.4 million, $1.5 million and $1.4 million for 2007, 2006 and 2005, respectively. (See "Summary of Cooperative Operations – Rates and Regulation.")

Financial Condition

Overview

    Oglethorpe's financial condition remained stable at December 31, 2007. A Margins for Interest Ratio of 1.10 was achieved for the year, as required by the Mortgage Indenture. This 1.10 margin coverage produced a net margin of $19 million, which caused a corresponding increase in patronage capital (equity), bringing total patronage capital to $517 million at December 31, 2007. Oglethorpe's equity to capitalization ratio was 12.3 percent at year end 2007, and was unchanged from year end 2006.

    Oglethorpe maintained a strong liquidity position with $841 million of unrestricted available liquidity at December 31, 2007.

    There was a net increase in long-term debt outstanding of $142 million due mostly to the advance of funds under approved RUS loans and an issuance of first mortgage bonds in 2007. The average interest rate on the $3.3 billion of long-term debt outstanding at December 31, 2007 was 5.4 percent.

    Property additions totaled $195 million and were financed with a combination of funds from operations and long-term borrowings. The expenditures were primarily for purchases of nuclear fuel, normal additions and replacements to existing generation facilities and environmental control facilities being installed at the coal-fired generating plants.

    The three major rating agencies have all assigned investment grade credit ratings to Oglethorpe (see "Credit Rating Risk" below).

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Liquidity and Sources of Capital

    Sources of Capital.    Oglethorpe has historically obtained the majority of its long-term financing from RUS-guaranteed loans funded by FFB. However, RUS-guaranteed funding for new generation facilities is uncertain and may be limited at any point in the future due to budgetary pressures faced by Congress (see "OGLETHORPE POWER CORPORATION – Relationship with RUS"). In addition, over the next ten years the loan demand of electric cooperatives is projected to exceed RUS-guaranteed funding authorization levels unless there is an increase over current levels of funding.

    Oglethorpe has also obtained a substantial portion of its long-term financing requirements from the issuance of bonds in the taxable and tax-exempt capital markets, and expects that it will be able to access both these markets in the future. However, the types of equipment that will qualify for tax-exempt financing are fewer than in the past due to changes in tax laws and regulations.

    Therefore, any generation facilities that Oglethorpe may build in the future on behalf of its Members will likely be financed through a variety of sources, including RUS-guaranteed loans, capital market financings (both taxable and tax-exempt), and possibly private placement and other financing sources.

    In addition, Oglethorpe's operations have historically provided a sizable contribution to its funding of capital requirements, such that internally generated funds have provided interim funding or long-term capital for nuclear fuel purchases, replacements and additions to existing generating facilities, general plant additions, and retirement of long-term debt. However, due to the significant amount of expenditures currently underway relating to environmental compliance at its coal-fired generating facilities, in the future Oglethorpe anticipates that it will meet its capital requirements through a combination of funds generated from operations and short and long-term borrowings. See "Capital Requirements – Capital Expenditures" for more detailed information regarding Oglethorpe's estimated expenditures related to environmental compliance. See "Financing Activities" for detailed information regarding Oglethorpe's financing plans.

    Liquidity.    At December 31, 2007, Oglethorpe had $841 million of unrestricted available liquidity to meet short-term cash needs and liquidity requirements. This amount included $291 million of cash and cash equivalents and $550 million of unused committed credit arrangements.

    Oglethorpe also had $47 million invested in auction rate securities of other companies at December 31, 2007. These securities have maturities in excess of one year and as such are classified as long-term investments. Auction rate securities re-price in Dutch auctions that occur every 7 to 35 days, and Oglethorpe can seek to liquidate these securities at the end of any auction period. Recently, however, there have been failed auctions on some of the auction rate investments held by Oglethorpe, requiring Oglethorpe to hold the investments during the subsequent auction period. Oglethorpe is currently liquidating these investments when possible. See "Negative Events in the Capital Markets" for a more detailed discussion of current events in the capital markets causing failed auctions.

    In addition to unrestricted available liquidity, Oglethorpe had $48 million in restricted cash and cash equivalents at December 31, 2007. The $48 million was on deposit with a bond trustee relating to PCBs issued in October 2007, the proceeds of which were used in January 2008 to refinance $18 million of PCB amortizing maturities and to redeem $30 million of PCB bullet maturities (see "Financing Activities").

    Net cash provided by operating activities was $172 million in 2007 (about $20 million less than in 2006), and averaged $222 million for the three-year period 2005 through 2007.

    The $550 million of credit arrangements mentioned above is comprised of three separate facilities as reflected in the table below:

Committed Short-Term Credit Facilities
(dollars in millions)
			Authorized Amount		Available Amount	Expiration Date
Commercial Paper
	Backup Line of Credit	$	450	$	450	July 2012
CoBank Line of Credit			50		50	November 2008
CFC Line of Credit			50		50	October 2008

    Oglethorpe expects to renew these short-term credit facilities, as needed, prior to their respective expiration dates. All of the credit facilities provide for both bank rate and LIBOR based borrowings.

    Under the commercial paper program Oglethorpe is authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup

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lines of credit, thereby providing 100 percent 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 $450 million committed backup credit facility that runs through 2012, provided by a group of seven banks that was syndicated by Bank of America. The commercial paper backup line of credit contains a financial covenant requiring Oglethorpe to maintain minimum patronage capital of $400 million plus 75 percent of each year's positive net margin. As of December 31, 2007, the required amount equaled $414 million, and Oglethorpe's year-end patronage capital exceeded this amount by $103 million. An additional covenant under this facility limits Oglethorpe's secured indebtedness to $8.5 billion and unsecured indebtedness to $4.0 billion during the term of the credit agreement, and Oglethorpe's debt levels are significantly below these thresholds.

    Along with the lines of credit from CoBank and the National Rural Utilities Cooperative Finance Corporation ("CFC"), funds may be advanced under the backup line of credit supporting commercial paper for general working capital needs. In addition, under both the CoBank line of credit and the backup line supporting commercial paper, Oglethorpe has the ability to issue letters of credit to third parties in amounts up to $50 million under each facility, or $100 million in the aggregate. However, due to the requirement to have 100 percent dedicated backup for any outstanding commercial paper, if any amounts are drawn under the commercial paper backup line for working capital or for the purpose of issuing letters of credit, it will reduce the amount of commercial paper that Oglethorpe can issue.

    Liquidity Covenants.    At December 31, 2007, Oglethorpe had three financial agreements in place containing liquidity covenants. These agreements included the two interest rate swaps relating to PCB transactions and the Rocky Mountain lease transactions. However, effective March 2008, the interest rate swaps were terminated, leaving only the liquidity covenant under the Rocky Mountain lease transaction. This covenant requires Oglethorpe to maintain minimum liquidity of $50 million at all times during the term of the lease. Oglethorpe estimates that it will have more than sufficient liquidity to satisfy this requirement in 2008. See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Interest Rate Risk – Interest Rate Swap Transactions" for a detailed discussion of the swap terminations.

Financing Activities

    Oglethorpe currently has three approved loans and one pending loan application at the RUS. The three approved loans total $612 million and are for the purpose of funding: (i) approximately $185 million of normal additions and replacements at existing generation facilities through 2011, and (ii) approximately $427 million of expenditures through 2014 relating to compliance with environmental regulations. Two of the three approved RUS loans have closed, and to date, $64 million has been advanced thereunder. Oglethorpe does not expect to have all three loans fully drawn until year-end 2014.

    All of the approved RUS loans will be funded through the FFB and guaranteed by the RUS, and the debt will be secured under Oglethorpe's Mortgage Indenture.

    The pending RUS loan application is for $1.8 billion to fund Oglethorpe's potential 30 percent undivided interest in two new proposed nuclear units that may be built at the existing Plant Vogtle site. This loan application was submitted in December 2006 and Oglethorpe does not expect RUS to act on it until 2009 at the earliest. The industry has experienced dramatic increases in the forecasted cost of materials and labor for such facilities, and it is likely that additional funds will be required, should Oglethorpe decide to participate. See "BUSINESS – OGLETHORPE'S POWER SUPPLY RESOURCES – Future Power Resources" and "Executive Overview" for a discussion of Oglethorpe's potential participation in these proposed units. See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with RUS" for a discussion of RUS's current position relating to funding of new generation facilities.

    In the near future, Oglethorpe has plans to submit additional loan applications to the RUS covering both general improvements at existing generation facilities and costs associated with environmental compliance at coal-fired Plant Scherer. It is anticipated that these loan applications in the aggregate will total approximately $300 million.

    Oglethorpe has received tax-exempt financing allocations from the state of Georgia totaling $200 million. $50 million was received in 2005 and

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relates to scrubbers being installed at Plant Wansley to reduce sulfur dioxide emissions. $150 million was received in 2006 and relates to equipment being installed at Plant Scherer to control mercury emissions, although it is uncertain at this time if enough of this equipment will qualify to take advantage of the full amount of the allocation. The tax-exempt bonds can be issued any time within a three-year window that begins the year after the allocation was awarded. Currently, Oglethorpe anticipates issuing tax-exempt bonds for both projects in the fall of 2008.

    In 2006, Oglethorpe received an allocation from the Internal Revenue Service ("IRS") to issue $24 million of Clean Renewable Energy Bonds ("CREBs") to fund an upgrade project currently underway at its Rocky Mountain generating facility. CREBs are zero coupon bonds, and in lieu of receiving an interest payment from the issuer the bondholder receives a credit against federal income tax liability. Oglethorpe had its CREB application submitted to the IRS on its behalf by CFC, along with the applications of other electric cooperatives. CFC, as a qualified issuer under the program, will issue the bonds and in turn loan the proceeds at a low rate of interest (approximately one percent) to the cooperatives whose applications were approved. Unless federal authority for CREBs is expanded, the bonds must be issued by December 31, 2008. Oglethorpe anticipates closing its CREBs related loan with CFC later in 2008.

    Oglethorpe has a program in place under which it is refinancing, on a continued tax-exempt basis, the annual principal maturities of pollution control bonds ("PCBs") 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, approximately $260 million has been refinanced under this program, including $22 million of PCB principal that matured in January 2008 (of which GTC had an assumed obligation to pay $3.7 million, as discussed below). In the fall of 2008, Oglethorpe plans to refinance an additional $10 million of PCB principal that matures in January 2009 (of which GTC has an assumed obligation to pay $1.7 million) and has Board approval to continue this refinancing program for PCB principal maturities through 2019.

    Under an indemnity agreement executed in connection with GTC's assumption of PCB indebtedness as part of a 1997 corporate restructuring (see "Off-Balance Sheet Arrangements – GTC Debt Assumption") and a new indemnity agreement executed in connection with GTC's assumption of PCB refunding indebtedness in October 2006, GTC is entitled to participate in any future prepayment of assumed PCB debt by agreeing to assume a portion of the refunding indebtedness. As such, GTC elected to participate in the refinancing of the January 2008 maturities discussed above, and Oglethorpe anticipates that GTC will continue to participate in these annual refinancings for the foreseeable future.

    In connection with the extension of the Wholesale Power Contracts from 2025 to 2050, Oglethorpe embarked on a program in 2006 to refinance or otherwise reamortize a portion of its PCB and FFB debt. An extension of the debt maturities provides for better alignment of principal amortization with the projected useful lives of Oglethorpe's assets, which are currently projected to operate well beyond the original contract termination date of 2025. To date, Oglethorpe has extended the maturities on approximately $1.4 billion of its FFB and PCB indebtedness. Included in this amount were three separate transactions that closed in 2007 covering $870 million of FFB debt and $182 million of PCB debt. Oglethorpe plans to complete its debt reamortization program through a refinancing of $123 million of PCB bullet maturities, along with $10 million of PCB amortizing principal scheduled to mature in January 2009 and the recently allocated tax-exempt debt discussed above, in a single transaction which is expected to close in the fall of 2008.

Negative Events in the Capital Markets

    The three major credit rating agencies are in the process of an on-going review of the monoline bond insurers as a result of the exposure some insurers have to financial guarantees provided on structured finance obligations backed by subprime residential mortgages. Several bond insurers have already been downgraded below their historical triple-A rating levels or have had negative outlooks assigned to their triple-A ratings, including three insurers that provide guarantees on a significant portion of Oglethorpe's outstanding variable rate PCB indebtedness.

    Bond insurer downgrades have been most material as it relates to their impact on auction rate securities ("ARS") guaranteed by the insurer, leading to increased focus on the underlying issuer credit, wider credit

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spreads, and failed auctions. A bond insurer downgrade can also affect the credit spread of insured variable rate demand bonds ("VRDB"), but currently less than ARS due to bank liquidity support on a VRDB which allows bonds to be put to the liquidity facility in the event of a failed remarketing.

    Oglethorpe currently has outstanding $434 million of PCBs in the ARS mode and $410 million of PCBs in the VRDB mode. Oglethorpe has recently seen some of its ARS auctions fail due to investors moving away from this market, and has also had VRDBs put to the supporting bank liquidity facilities due to the remarketing agents' inability to remarket the bonds as a result of a downgrade of the bond insurer. These events have resulted in higher variable rates of interest on the bonds, in some instances as high as 12 percent. The weighted average interest rate on Oglethorpe's PCBs in the ARS mode was approximately 4 percent and 7 percent at December 31, 2007 and March 19, 2008, respectively.

    In light of these events, in a remarketing expected to close in April 2008, Oglethorpe plans to convert $312 million of its PCBs from the ARS mode to another interest rate mode as it has the option to do pursuant to the underlying bond documents. Oglethorpe also plans to refinance the balance of its PCBs in the ARS mode ($123 million) in a transaction that is expected to close in October 2008 (see "Financing Activities").

    In a transaction expected to close in May 2008, Oglethorpe expects to refinance $255 million of PCBs that are currently in a weekly VRDB mode (due to a downgrade of the existing bond insurer) through the issuance of $255 million of Series 2008 refunding bonds. While this transaction is being undertaken mainly to replace the bond insurer, this transaction will also provide for an immediate extension of the maturities, rather than over time as the principal on this PCB debt was set to mature each year.

    See also "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Interest Rate Risk – Interest Rate Swap Transactions" for a discussion of the impacts on Oglethorpe's interest rate swap arrangements related to a bond insurer downgrade.

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 2008 through 2010. Actual expenditures may vary from the estimates listed in the table because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor.

Capital Expenditures (1)
(dollars in millions)
Year		Existing Generation		Environmental Compliance		Nuclear Fuel		General Plant		Total
2008	$	71	$	186	$	87	$	4	$	348
2009		56		152		93		2		303
2010		35		114		89		1		239
Total	$	162	$	452	$	269	$	7	$	890

(1)

Excludes allowance for funds used during construction.

    In addition to the expenditures reflected in the table above, Oglethorpe expects to pay GPC up to $40 million in connection with the nuclear development option agreement by July 2008, the currently scheduled date by which Oglethorpe must commit to the project, or reduce its participation, either partially or completely, in up to two additional nuclear units at Plant Vogtle and receive a refund of these costs (pro rata with interest). For information about preliminary steps Oglethorpe has taken to procure financing in the event it elects to participate in these new nuclear units, see "Financing Activities." For a more detailed discussion of the nuclear development option agreement, see "BUSINESS – OGLETHORPE'S POWER SUPPLY RESOURCES – Future Power Resources."

    In addition to potential participation in two new nuclear units at Plant Vogtle, Oglethorpe has identified electric generation options that it could pursue to meet the Members' future energy needs (see "OGLETHORPE'S POWER SUPPLY RESOURCES – Future Power Resources"), including the possible construction of new facilities that are not included in the capital expenditure table above. The projects that Oglethorpe may ultimately construct, if any, as well as the cost of construction, are not known at this time.

    Oglethorpe is subject to environmental regulations and may be subject to future additional environmental regulations, including future implementation of existing laws and regulations. Since alternative legislative and regulatory environmental compliance programs continue

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to be debated on a national level (in particular as it relates to climate change), it is difficult to predict what capital costs may ultimately be required. The environmental compliance expenditures reflected in the table above include the installation of (i) a flue gas desulfurization project (scrubbers) currently underway at Plant Wansley, and (ii) a mercury removal project, a flue gas desulfurization project and a selective catalytic reduction project underway at Plant Scherer. Under the current schedule, all of these environmental compliance projects will be in service by 2014, and are estimated to require an additional $450 million of capital expenditures in the period 2011 through 2014.

    Depending on how Oglethorpe and the other co-owners of Plants Wansley and Scherer choose to comply with any future regulations, both capital expenditures and operating expenditures may be impacted. In any event, as required by the Wholesale Power Contracts, Oglethorpe expects to be able to recover from its Members all capital and operating expenditures made in complying with current and future environmental regulations.

    For additional information, see "BUSINESS – ENVIRONMENTAL AND OTHER REGULATION – Clean Air Act."

    Contractual Obligations.    The table below reflects, as of December 31, 2007, Oglethorpe's contractual obligations for the periods indicated.

Contractual Obligations
(dollars in millions)
			2008		2009- 2010		2011- 2012		Beyond 2012		Total
Long-Term Debt:
	Principal	$	118	$	194	$	232	$	2,796	$	3,340
	Interest (1)		179		343		317		1,988		2,827
Capital Leases (2)			44		89		89		198		420
Operating Leases			5		10		11		32		58
Unconditional Power Purchases			77		57		59		216		409
Rocky Mtn. Lease Transactions (3)			–		–		–		372		372
Chattahoochee O&M Agmts.			19		42		43		139		243
Asset Retirement Obligations (4)			–		–		–		2,452		2,452
Total		$	442	$	735	$	751	$	8,193	$	10,121

1)

Includes interest expense related to variable rate debt. Future variable rates are based on a forward SIFMA interest rate curve as of February 2008.

2)

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

3)

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

4)

A substantial portion of this amount relates to the decommissioning of nuclear facilities.

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.

Credit Rating Risk

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

Oglethorpe Ratings	S&P	Moody's	Fitch
Senior secured debt	A	A3	A
Short-term/commercial paper	A-1	P-2	F1

    Oglethorpe has financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of either letters of credit, surety bonds or cash.

    Provisions in the Rocky Mountain lease transactions could require Oglethorpe to post surety bonds or letters of credit in the amount of $50 million if Oglethorpe fails to maintain at least two "triple-B" ratings on its senior secured debt (if any and if rated) and at least two "triple-B minus" ratings on its senior unsecured debt (if any and if rated) from Standard & Poor's, Moody's Investors Service and Fitch Ratings.

    Provisions in the RUS Loan Contract, certain PCB loan agreements and the commercial paper backup line of credit agreement contain covenants based on credit ratings that could result in increased interest rates or restrictions on issuing debt. Also, borrowing rates and commitment fees in the CFC and commercial paper line of credit agreements are based on credit ratings and could therefore increase if Oglethorpe's ratings are lowered. None of these covenants, however, would result in acceleration of any debt.

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

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Off-Balance Sheet Arrangements

    Oglethorpe is liable for certain contractual obligations for 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 Debt Assumption.    In connection with a corporate restructuring in 1997 in which Oglethorpe sold its transmission related assets to GTC (which represented 16.86 percent of Oglethorpe's assets), GTC assumed 16.86 percent of the then outstanding indebtedness associated with PCBs pursuant to an Assumption Agreement and an Indemnity Agreement. If GTC fails to satisfy its obligations under this debt assumption, 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, 2007, the total obligation assumed by GTC relating to outstanding PCB principal was $94 million. GTC's estimated payments of principal and interest in 2008 pursuant to this assumed obligation is approximately $9 million.

    For a discussion of GTC's assumed 16.86 percent obligation (also in connection with the 1997 corporate restructuring) in two of Oglethorpe's interest rate swap transactions that were recently terminated, see "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Interest Rate Risk – Interest Rate Swap Transactions."

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

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

•

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

•

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

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

    The Facility Subleases require Oglethorpe to make semi-annual rental payments to RMLC. In turn, RMLC is required to make identical rental payments to the owner trusts under the Facility Leases. In 2007, the amount of the rental payments under the Facility Subleases and Facility Leases each totaled $54 million. The payment undertaking agreements require the other party (the "payment undertaker") to pay the rent payments directly to the owner trust's lender in satisfaction of RMLC's rent payment obligation under the Facility Lease and the applicable owner trust's repayment obligation under the loan to it. Because RMLC funds these rent payments through the payment undertaking agreements, RMLC returns to Oglethorpe amounts received by it pursuant to the Facility Subleases. RMLC remains liable for all rental payments under the Facility Leases if the payment undertaker fails to make such payments, although the owner trusts have agreed to use due diligence to pursue the payment undertaker before pursuing payment from RMLC or Oglethorpe.

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    The senior unsecured debt obligations of the payment undertaker are rated "AAA" by S&P and "Aaa" by Moody's, and the senior unsecured debt obligations of the third party to the funding agreement are rated "AA" by S&P and "Aa2" by Moody's.

    As a wholly owned subsidiary of Oglethorpe, the financial condition and results of operations of RMLC are fully consolidated into Oglethorpe's financial statements. The funding agreements and corresponding lease obligations are reflected on the balance sheets of RMLC and Oglethorpe as Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions (both $101 million at December 31, 2007). However, the financial statements of RMLC and Oglethorpe do not reflect the payment undertaking agreements or the corresponding lease obligations, or the payments made by the payment undertaker, including the payments of rent under the Facility Leases and Facility SubLeases, because they have been extinguished for financial reporting purposes. If RMLC's interests in the payment undertaking agreements and the corresponding lease obligations were reflected on the balance sheets of RMLC and Oglethorpe at December 31, 2007, both the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions would have been higher by $709 million.

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

•

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

•

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

•

retaining the undivided interest for its own benefit.

    Under the first two of these options Oglethorpe must arrange new financing for the outstanding loans to the 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 percent, in the case of the first option above, or all, in the case of the second option above, of the debt or cause RMLC to exercise its purchase option or RMLC and Oglethorpe to renew the Facility Leases and Facility Subleases, respectively.

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

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Interest Rate Risk

    Oglethorpe is exposed to the risk of changes in interest rates related to its approximately $840 million of variable rate PCB debt. 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 percent and 30 percent variable rate debt to total debt. At December 31, 2007, Oglethorpe had 19 percent of its debt (including capital lease debt) in a variable rate mode.

    The table below details Oglethorpe's existing debt instruments and provides the fair value at December 31, 2007, the outstanding balance at the beginning and end of each year and the annual principal maturities and associated average interest rates.

		(dollars in thousands)
	Fair Value			Cost
		2007			2008			2009			2010			2011			2012			Thereafter
Fixed Rate Debt
Beginning of year				$	2,517,318		$	2,440,144		$	2,359,016		$	2,274,966		$	2,186,719		$	2,094,099
Maturities					(77,174	)		(81,128	)		(84,050	)		(88,247	)		(92,620	)
End of year	$	2,681,647		$	2,440,144		$	2,359,016		$	2,274,966		$	2,186,719		$	2,094,099
Average interest rate on maturing fixed rate debt					5.74%			5.79%			5.85%			5.91%			5.96%			5.76%
Variable Rate Debt(1)(2)
Beginning of year				$	891,720		$	851,280		$	846,048		$	822,541		$	795,548		$	771,755
Maturities					(40,440	)		(5,232	)		(23,507	)		(26,993	)		(23,793	)
End of year	$	669,614		$	851,280		$	846,048		$	822,541		$	795,548		$	771,755
Average interest rate on maturing variable rate debt					4.12%			4.10%			4.16%			4.16%			4.17%			4.15%
Interest Rate Swaps (2)
Beginning of year					$  0			$  0			$  0			$  0			$  0			$  0
Maturities					0			0			0			0			0
End of year	$	222,085			$  0			$  0			$  0			$  0			$  0
Unrealized loss on swaps	$	(30,526	)

(1)

Future variable interest rates are based on a forward SIFMA yield curve as of February 2008.

(2)

Debt underlying the interest rate swaps was variable rate PCB debt that was swapped to a contractual fixed rate of interest. Effective March 2008, the swaps were terminated. Therefore, the underlying debt is reflected as variable rate debt in this table beginning in 2008.

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    Substantially all of the variable rate debt in the above table is comprised of variable rate PCB debt, which had a weighted average interest rate of 3.88 percent at January 1, 2008. If interest rates on this debt increased 100 basis points, interest expense would increase by approximately $6 million on an annualized basis. The operative documents underlying this debt contain provisions that allow Oglethorpe to convert the debt to a variety of variable interest rate modes (such as daily, weekly, monthly, commercial paper or auction rate mode), or to convert the debt to a fixed rate of interest for a specified term or to maturity. This optionality improves Oglethorpe's ability to manage its exposure to variable interest rates.

    At any point in time, Oglethorpe may analyze and consider using various types of derivative products (including swaps, caps, floors and collars) to help manage its interest rate risk. To-date, however, Oglethorpe's use of interest rate derivatives has been limited to the swap transactions described below.

Interest Rate Swap Transactions

    At December 31, 2007, Oglethorpe had two interest rate swap arrangements in place with AIG Financial Products Corp. ("AIG-FP") as swap counterparty, which were designed to create a contractual fixed rate of interest on $322 million of variable rate PCBs. These transactions were entered into in early 1993 on a forward basis, pursuant to which approximately $200 million of variable rate PCBs were issued in November 1993 (the 1993 bonds) and approximately $122 million of variable rate PCBs were issued in December 1994 (the 1994 bonds). Oglethorpe is obligated to pay the variable interest rate that accrues on these PCBs; however, the swap arrangements provided a mechanism for Oglethorpe to achieve a contractual fixed rate which was lower than Oglethorpe would have obtained had it issued fixed rate bonds at that time.

    In connection with the 1997 corporate restructuring, GTC assumed and agreed to pay 16.86 percent of any amounts due from Oglethorpe under these swap arrangements, including the net swap payments and any termination payments made. Under the swap arrangements, Oglethorpe was obligated to make periodic payments to AIG-FP based on a notional principal amount equal to the aggregate principal amount of the bonds outstanding during the period and a contractual fixed rate ("Fixed Rate"), and AIG-FP was obligated to make periodic payments to Oglethorpe based on a notional principal amount equal to the aggregate principal amount of the bonds outstanding during the period and a variable rate equal to the variable rate of interest accruing on the bonds during the period ("Variable Rate"). These payment obligations were netted, such that if the Variable Rate was less than the Fixed Rate, Oglethorpe made a net payment to AIG-FP. Likewise, if the Variable Rate was higher than the Fixed Rate, Oglethorpe received a net payment from AIG-FP. Thus, although changes in the Variable Rate affected whether Oglethorpe was obligated to make payments to AIG-FP or was entitled to receive payments from AIG-FP, the effective interest rate Oglethorpe paid with respect to the PCBs was not affected by changes in interest rates. The Fixed Rate on the 1993 bonds was 5.67 percent and the Fixed Rate on the 1994 bonds was 6.01 percent. At December 31, 2007, there was $165 million of 1993 bonds outstanding (carrying a variable rate of interest of 3.52 percent) and $103 million of 1994 bonds outstanding (carrying a variable rate of interest of 3.43 percent). For the three years ended December 31, 2005, 2006 and 2007, Oglethorpe made in connection with both interest rate swap arrangements combined net swap payments to AIG-FP (net of amounts assumed by GTC) of $8.0 million, $5.0 million and $5.0 million, respectively.

    At December 31, 2007 Oglethorpe also had two swaps in place with JPMorgan Chase Bank ("JPMC") as swap counterparty that became effective in August 2006. These swaps also used as notional principal Oglethorpe's share of the 1993A and 1994A bonds and were designed to convert the variable rate of interest Oglethorpe received under the swaps with AIG-FP to a longer-term contractual variable rate of interest that Oglethorpe received from JPMC.

    In February 2008, Oglethorpe received notice from AIG-FP of its election to begin paying an alternative variable rate under the swaps that is based on the Securities Industry and Financial Markets Association ("SIFMA") municipal swap index rather than the variable rate accruing on the bonds. AIG-FP had the right to make this election due to a downgrading of the 1993A and 1994A bonds below "AA-"or "Aa3" by S&P or Moody's, respectively. The bonds were downgraded in February 2008 in connection with recent downgrades of Financial Guaranty Insurance Company ("FGIC"), the entity guaranteeing payment of principal

46

and interest on the bonds, to "A" by S&P and to "A3" by Moody's. At the point AIG-FP began making payments to Oglethorpe based on the SIFMA index, Oglethorpe's all-in cost under the swap arrangements increased significantly. The bond downgrades and AIG-FP's election to use the SIFMA index triggered options for Oglethorpe to terminate the swaps with AIG-FP. Oglethorpe exercised these options effective March 14, 2008, and made termination payments to AIG-FP of approximately $37 million (net of amounts assumed and paid by GTC).

    In connection with the termination of the swaps with AIG-FP, Oglethorpe also elected to terminate the swaps with JPMC effective March 14, 2008, and in connection with the terminations received a payment from JPMC of approximately $3 million.

    See Footnote 2 of Notes to Consolidated Financial Statements for a discussion of the accounting treatment relating to the swap terminations.

Capital Leases

    In December 1985, Oglethorpe sold and subsequently leased back from four purchasers its 60 percent undivided ownership interest in Scherer Unit No. 2. The capital leases provide that Oglethorpe's rental payments vary to the extent of interest rate changes associated with the debt used by the lessors to finance their purchase of undivided ownership shares in the unit. The debt currently consists of $73 million in serial facility bonds due June 30, 2011 with a 6.97 percent fixed rate of interest.

    Oglethorpe entered into a power purchase and sale agreement with Doyle I, LLC to purchase all of the output from a five-unit gas-fired generation facility. The Doyle agreement is reported on Oglethorpe's balance sheet as a capital lease. The lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00 percent. At December 31, 2007, the weighted average interest rate on the lease obligation was 5.95 percent.

Equity Price Risk

    Oglethorpe maintains external trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning. (See Note 1 of Notes to Consolidated Financial Statements.) As of December 31, 2007, these funds were invested in U.S. Government securities, domestic and international equities and global fixed income securities. Oglethorpe also maintains an internal decommissioning reserve from which funds can be transferred to the external trust fund, should that be necessary. By maintaining a portfolio that includes long-term equity investments, Oglethorpe intends to maximize the returns to be utilized to fund nuclear decommissioning, which in the long-term will better correlate to inflationary increases in decommissioning costs. However, the equity securities included in Oglethorpe's portfolio (in both the internal and external fund) are exposed to price fluctuation in equity markets. A 10 percent decline in the value of the fund's equity securities as of December 31, 2007 would result in a loss of value to the fund of approximately $15 million. Oglethorpe actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets in its trusts to various investment options. Because realized and unrealized gains and losses from investment securities held in the decommissioning fund are directly added to or deducted from the decommissioning reserve, fluctuations in equity prices do not affect Oglethorpe's net margin in the short-term.

Commodity Price Risk

Coal

    Oglethorpe is also exposed to the risk of changing prices for fuels, including coal and natural gas. Oglethorpe has interests in 1,501 MW of coal-fired capacity (Plants Scherer and Wansley). Oglethorpe purchases coal under term contracts and in spot-market transactions. Some of Oglethorpe's coal contracts provide volume flexibility and most have fixed or capped prices. Oglethorpe anticipates that its existing contracts will provide fixed prices for over 97 percent of its forecasted coal requirements in 2008 and fixed or capped prices for over 90 percent of its forecasted coal requirements in 2009.

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

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Natural Gas

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

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

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

    Oglethorpe enters into natural gas swap arrangements to manage its exposure to fluctuations in the market price of natural gas. Under these swap agreements, Oglethorpe pays the counterparty a fixed price for specified natural gas quantities and receives a payment for such quantities based on a market price index. These payment obligations are netted, such that if the market price index is lower than the fixed price, Oglethorpe will make a net payment, and if the market price index is higher than the fixed price, Oglethorpe will receive a net payment. If the natural gas swaps had been terminated on December 31, 2007, Oglethorpe would have made a net payment of approximately $222,960. Oglethorpe has obtained the Members' approval required by the New Business Model Member Agreement to continue to manage exposures to natural gas price risks for Members that elect to receive such services. Oglethorpe is providing natural gas price risk management services to 14 of its Members. At the beginning of each calendar year, additional Members may elect to receive these services. Members may elect to discontinue receiving these services at any time.

Changes in Risk Exposure

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index To Financial Statements

	Page
Consolidated Statements of Revenues and Expenses, For the Years Ended December 31, 2007, 2006 and 2005	51
Consolidated Balance Sheets, As of December 31, 2007 and 2006	52
Consolidated Statements of Capitalization, As of December 31, 2007 and 2006	54
Consolidated Statements of Cash Flows, For the Years Ended December 31, 2007, 2006 and 2005	55
Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit For the Years Ended December 31, 2007, 2006 and 2005	56
Notes to Consolidated Financial Statements	57
Report of Independent Registered Public Accounting Firm	77

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES

For the years ended December 31, 2007, 2006 and 2005

			(dollars in thousands)
			2007			2006			2005
Operating revenues:
	Sales to Members	$	1,149,657		$	1,127,423		$	1,136,463
	Sales to non-Members		1,585			1,456			33,060
Total operating revenues			1,151,242			1,128,879			1,169,523
Operating expenses:
	Fuel		415,125			374,144			365,073
	Production		246,675			254,658			251,830
	Purchased power		155,005			179,129			255,616
	Depreciation and amortization		131,908			157,303			153,030
	Accretion		19,326			21,932			33,996
	Gain on sale of emission allowances		(394	)		(39,529	)		(83,098	)
Total operating expenses			967,645			947,637			976,447
Operating margin			183,597			181,242			193,076
Other income (expense):
	Investment income		46,788			46,313			36,060
	Amortization of deferred gains		5,660			5,660			5,660
	Allowance for equity funds used during construction		1,802			904			355
	Other		4,235			3,592			3,048
Total other income			58,485			56,469			45,123
Interest charges:
	Interest on long-term debt and capital leases		212,003			204,317			203,124
	Other interest		2,253			3,046			3,321
	Allowance for debt funds used during construction		(6,962	)		(3,437	)		(1,681	)
	Amortization of debt discount and expense		15,727			15,584			15,782
Net interest charges			223,021			219,510			220,546
Net margin		$	19,061		$	18,201		$	17,653

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

51

OGLETHORPE POWER CORPORATION
CONSOLIDATED BALANCE SHEETS

December 31, 2007 and 2006

			(dollars in thousands)
			2007			2006
Assets
Electric plant:
	In service	$	5,792,476		$	5,769,129
	Less: Accumulated provision for depreciation		(2,630,522	)		(2,495,049	)
			3,161,954			3,274,080
	Nuclear fuel, at amortized cost		130,138			119,076
	Construction work in progress		189,102			68,145
Total electric plant			3,481,194			3,461,301
Investments and funds:
	Decommissioning fund, at market		239,974			233,309
	Deposit on Rocky Mountain transactions, at cost		101,272			94,772
	Bond, reserve and construction funds, at market		5,614			6,397
	Investment in associated companies, at cost		46,449			43,331
	Long-term investments, at market		109,170			118,281
	Other, at cost		1,502			1,478
Total investments and funds			503,981			497,568
Current assets:
	Cash and cash equivalents, at cost		290,930			423,757
	Restricted cash, at cost		48,124			18,312
	Receivables		60,672			91,360
	Inventories, at average cost		149,871			135,996
	Prepayments and other current assets		4,780			4,234
Total current assets			554,377			673,659
Deferred charges:
	Premium and loss on reacquired debt, being amortized		140,829			112,147
	Deferred amortization of capital leases		91,446			95,450
	Deferred debt expense, being amortized		37,356			30,072
	Deferred outage costs, being amortized		29,833			25,782
	Deferred tax assets		72,000			–
	Other		26,304			5,766
Total deferred charges			397,768			269,217
Total assets		$	4,937,320		$	4,901,745

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

52

OGLETHORPE POWER CORPORATION
CONSOLIDATED BALANCE SHEETS

December 31, 2007 and 2006

			(dollars in thousands)
			2007			2006
Equity and Liabilities
Capitalization:
	Patronage capital and membership fees	$	516,570		$	497,509
	Accumulated other comprehensive deficit		(32,691	)		(28,988	)
			483,879			468,521
	Long-term debt		3,291,424			3,197,478
	Obligations under capital leases		260,943			283,816
	Obligation under Rocky Mountain transactions		101,272			94,772
Total capitalization			4,137,518			4,044,587
Current liabilities:
	Long-term debt and capital leases due within one year		143,400			234,621
	Accounts payable		41,621			31,662
	Accrued interest		20,153			54,489
	Accrued and withheld taxes		7,122			41,755
	Other current liabilities		17,311			9,167
Total current liabilities			229,607			371,694
Deferred credits and other liabilities:
	Gain on sale of plant, being amortized		36,011			38,485
	Net benefit of Rocky Mountain transactions, being amortized		60,521			63,707
	Asset retirement obligations		265,326			249,575
	Accumulated retirement costs for other obligations		53,327			56,220
	Deferred liability associated with retirement obligations		5,568			11,085
	Interest rate swap arrangements		32,806			29,417
	Long-term contingent liability		72,000			–
	Other		44,636			36,975
Total deferred credits and other liabilities			570,195			485,464
Total equity and liabilities		$	4,937,320		$	4,901,745
Commitments and Contingencies (Notes 1, 5, 9, 11 and 12)

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

53

OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31, 2007 and 2006

				(dollars in thousands)
				2007			2006
Long-term debt:
	Mortgage notes payable to the Federal Financing Bank ("FFB") at interest rates varying from 3.89% to 8.43% (average rate of 5.67% at December 31, 2007) due in quarterly installments through 2041		$	1,661,751		$	2,184,481
	Mortgage notes payable to Rural Utilities Service ("RUS") at an interest rate of 5% due in monthly installments through 2020			9,872			10,445
	Mortgage bonds payable:
		• Series 2006     Term Bonds, 5.534% due 2031 through 2035		300,000			300,000
		• Series 2007     Term Bonds, 6.191% due 2024 through 2031		500,000			–
	Mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds ("PCBs"):
		• Series 1992A     Serial bonds, 6.65% to 6.80%, due serially from 2008 through 2012		45,696			53,195
		• Series 1993A     Adjustable tender bonds, 3.52%, due 2008 through 2016		136,771			143,688
		• Series 1994A     Adjustable tender bonds, 3.43%, due 2008 through 2019		85,314			88,502
		• Series 2002A and 2002B     Auction rate bonds, fully redeemed December 2007		–			91,990
		• Series 2002 and 2002C     Adjustable tender bonds, 3.49% to 3.74%, due 2018		30,075			30,075
		• Series 2003A and 2003B     Auction rate bonds, 4.25% to 4.40%, due 2024		95,230			133,345
		• Series 2004     Auction rate bonds, 4.19%, due 2020		11,525			11,525
		• Series 2005     Auction rate bonds, 4.25% to 4.30%, due 2040		15,865			15,865
		• Series 2006A, 2006B-1, 2006B-2, 2006B-3, and 200B-4     Adjustable tender bonds, 3.03% to 3.60%, due 2036 through 2041		197,945			197,945
		• Series 2006B, 2006C-1, and 2006C-2     Auction rate bonds, 3.70% to 4.25%, due 2036 through 2037		133,550			133,550
		• Series 2007 A through F     Auction rate bonds, 3.65% to 4.40%, due 2038 through 2040		178,228			–
	CoBank, ACB notes payable:
		• Transmission mortgage note payable: fixed at 4.57%   through March 2, 2008, due in bimonthly installments through   November 1, 2018		1,457			1,519
		• Transmission mortgage note payable: fixed at 4.57% through   March 2, 2008, due in bimonthly installments through   September 1, 2019		5,759			5,969
Total long-term debt				3,409,038			3,402,094
Obligations under capital leases				286,729			313,821
Obligation under Rocky Mountain transactions, long-term				101,272			94,772
Patronage capital and membership fees				516,570			497,509
Accumulated other comprehensive deficit				(32,691	)		(28,988	)
	Subtotal			4,280,918			4,279,208
		Less: long-term debt and capital leases due within one year		(143,400	)		(234,621	)
Total capitalization			$	4,137,518		$	4,044,587

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

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OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2007, 2006 and 2005

				(dollars in thousands)
				2007			2006			2005
Cash flows from operating activities:
	Net margin		$	19,061		$	18,201		$	17,653
	Adjustments to reconcile net margin to net cash provided by operating activities:
		Depreciation and amortization, including nuclear fuel		222,808			234,156			225,366
		Accretion cost		19,326			21,932			33,996
		Amortization of deferred gains		(5,660	)		(5,660	)		(5,660	)
		Allowance for equity funds used during construction		(1,802	)		(904	)		(355	)
		Deferred outage costs		(36,550	)		(31,594	)		(23,654	)
		Other		(423	)		(1,024	)		(2,196	)
	Change in operating assets and liabilities:
		Receivables		28,946			7,416			34,174
		Inventories		(13,875	)		(41,422	)		6,353
		Prepayments and other current assets		(323	)		(221	)		106
		Accounts payable		1,050			(20,074	)		(15,908	)
		Accrued interest		(34,336	)		268			14,045
		Accrued and withheld taxes		(34,633	)		12,714			19,096
		Other current liabilities		8,051			(924	)		(2,201	)
	Total adjustments			152,579			174,663			283,162
Net cash provided by operating activities				171,640			192,864			300,815
Cash flows from investing activities:
	Property additions			(194,739	)		(134,518	)		(69,744	)
	Activity in decommissioning fund – Purchases			(544,584	)		(746,779	)		(690,224	)
	– Proceeds			526,832			725,387			677,085
	Activity in bond, reserve and construction funds – Purchases			(5,616	)		(1,124	)		(1,064	)
	– Proceeds			6,502			2,067			1,777
	Increase in restricted cash			(29,812	)		(2,156	)		(4,375	)
	Decrease (increase) in other short-term investments			–			231,798			(132,861	)
	Increase in investment in associated organizations			(1,491	)		(3,869	)		(4,268	)
	Activity in other long-term investments – Purchases			(649,694	)		(487,366	)		(471,276	)
	– Proceeds			660,956			418,056			483,525
	(Decrease) increase in Members' advances			–			(74,471	)		74,471
	Other			(5,265	)		(894	)		(2,563	)
Net cash used in investing activities				(236,911	)		(73,869	)		(139,517	)
Cash flows from financing activities:
	Long-term debt proceeds			755,135			631,495			24,512
	Long-term debt payments			(775,573	)		(486,914	)		(149,697	)
	Debt related costs			(51,693	)		(13,445	)		(2,905	)
	Other			4,575			2,892			3,857
Net cash provided by (used in) financing activities				(67,556	)		134,028			(124,233	)
Net increase (decrease) in cash and temporary cash investments				(132,827	)		253,023			37,065
Cash and temporary cash investments at beginning of period				423,757			170,734			133,669
Cash and temporary cash investments at end of period			$	290,930		$	423,757		$	170,734
Supplemental cash flow information:
	Cash paid for –
	Interest (net of amounts capitalized)		$	241,632		$	203,658		$	190,719
Supplemental disclosure of non-cash investing and financing activities:
	Plant expenditures included in ending accounts payable		$	10,099		$	(5,081	)	$	5,321

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

55

OGLETHORPE POWER CORPORATION
CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND
ACCUMULATED OTHER COMPREHENSIVE DEFICIT

For the years ended December 31, 2007, 2006 and 2005

			(dollars in thousands)
			Patronage Capital and Membership Fees		Accumulated Other Comprehensive Deficit			Total
Balance at December 31, 2004		$	461,655	$	(46,760	)	$	414,895
Components of comprehensive margin in 2005
	Net margin		17,653					17,653
	Unrealized gain on interest rate swap arrangements				10,344			10,344
	Unrealized gain on available-for-sale securities				918			918
Total comprehensive margin								28,915
Balance at December 31, 2005			479,308		(35,498	)		443,810
Components of comprehensive margin in 2006
	Net margin		18,201					18,201
	Unrealized gain on interest rate swap arrangements				6,326			6,326
	Unrealized gain on available-for-sale securities				184			184
Total comprehensive margin								24,711
Balance at December 31, 2006			497,509		(28,988	)		468,521
Components of comprehensive margin in 2007
	Net margin		19,061					19,061
	Unrealized loss on interest rate swap arrangements				(4,222	)		(4,222	)
	Unrealized gain on available-for-sale securities				519			519
Total comprehensive margin								15,358
Balance at December 31, 2007		$	516,570	$	(32,691	)	$	483,879

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2007, 2006 and 2005

1. Summary of significant accounting policies:

a. Business description

    Oglethorpe Power Corporation ("Oglethorpe") is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, GA. Oglethorpe is owned by 38 retail electric distribution cooperative members (the "Members"). The wholesale electric power provided by Oglethorpe consists of a combination of generating units totaling 4,744 megawatts ("MW") of capacity and power purchase agreements totaling 453 MW of capacity. These Members in turn distribute energy on a retail basis to approximately 4.1 million people.

b. Basis of accounting

    Oglethorpe's consolidated financial statements as of, and for the periods ended December 31, 2007 include Oglethorpe's accounts and the accounts of Oglethorpe's majority-owned and controlled subsidiaries. Oglethorpe has determined that there are no accounts of variable interest entities for which it is the primary beneficiary. This means that Oglethorpe's accounts are combined with the subsidiaries' accounts. Oglethorpe has eliminated any intercompany profits and transactions in consolidation.

    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 Rural Utilities Service ("RUS").

    The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2007 and 2006 and the reported amounts of revenues and expenses for each of the three years ending December 31, 2007. Actual results could differ from those estimates.

c. Patronage capital and membership fees

    Oglethorpe is organized and operates as a cooperative. The Members paid a total of $190 in membership fees. Patronage capital includes retained net margin of Oglethorpe. Any excess of revenue over expenditures from operations is treated as advances of capital by the Members and is allocated to each of them on the basis of the Members percentage capacity responsibility.

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

d. Accumulated comprehensive deficit

    The table below provides a detail of the beginning and ending balance for each classification of other comprehensive deficit along with the amount of any reclassification adjustments included in margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit (see Note 2). Oglethorpe's

57

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

Accumulated Other Comprehensive Deficit
		(dollars in thousands)
		Interest Rate Swap Arrangements			Available- for-sale Securities			Total
Balance at December 31, 2004	$	(45,254	)	$	(1,506	)	$	(46,760	)
Unrealized gain		10,344			918			11,262
Balance at December 31, 2005		(34,910	)		(588	)		(35,498	)
Unrealized gain		6,326			184			6,510
Balance at December 31, 2006		(28,584	)		(404	)		(28,988	)
Unrealized gain (loss)		(4,222	)		519			(3,703	)
Balance at December 31, 2007	$	(32,806	)	$	115		$	(32,691	)

e. Margin policy

    Oglethorpe is required under the Mortgage Indenture to produce a Margins for Interest ("MFI") Ratio of at least 1.10. For the years 2005, 2006 and 2007, Oglethorpe achieved a MFI ratio of 1.10.

f. Operating revenues

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

    Operating revenues from non-Members consisted primarily from services provided to Oglethorpe's former Member Flint EMC. In 2005, sales to non-Members were primarily from capacity and energy sales to Alabama Electric Cooperative under an agreement to sell 100 MW of capacity for the period June 1998 through December 2005. In addition, Oglethorpe sold short-term energy to non-Members for the benefit of Members participating in its capacity and energy pool. The capacity and energy pool was discontinued effective March, 2005.

    Revenues from Cobb EMC, Jackson EMC, and Sawnee EMC, three of Oglethorpe's Members, accounted for 13.3%, 12.3% and 10.0% in 2007, respectively, of Oglethorpe's total operating revenues. Revenues from Cobb EMC, and Jackson EMC accounted for 13.9% and 11.8% in 2006, and Cobb EMC, Jackson EMC, and Sawnee EMC accounted for 12.8%, 13.0%, and 10.4% in 2005, respectively, of Oglethorpe's total operating revenues.

g. Receivables

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

h. Nuclear fuel cost

    The cost of nuclear fuel, including a provision for the disposal of spent fuel, is being amortized to fuel expense based on usage. The total nuclear fuel expense for 2007, 2006 and 2005 amounted to $50,138,000, $45,299,000, and $44,395,000, respectively.

    Contracts with the U.S. Department of Energy ("DOE") have been executed to provide for the permanent disposal of spent nuclear fuel. DOE failed to begin disposing of spent fuel in January 1998 as required by the contracts, and Georgia Power Company ("GPC"), as agent for the co-owners of the plants, is pursuing legal remedies against DOE for breach of contract. An on-site dry storage facility for Plant Hatch is operational and can be expanded to accommodate spent fuel through the life of the plant. Plant Vogtle's spent fuel pool storage is expected to be sufficient for both units until 2015. Oglethorpe expects that procurement of on-site dry storage at Plant Vogtle will commence in sufficient time to maintain full-core discharge capability to the spent fuel pool.

58

    On July 9, 2007, the U.S. Court of Federal Claims found in favor of Southern Company and awarded damages in the amount of $59.9 million for Plant Hatch and Plant Vogtle. Oglethorpe's share of the award is $17.98 million. The decision has been appealed by the DOE. No amounts have been recognized in the financial statements as of December 31, 2007. The final outcome of this matter cannot be determined at this time. Oglethorpe's rate-making treatment of such future award received would be passed on to its Members.

i. Asset retirement obligations

    Asset retirement obligations are accounted and reported for under statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations" and Financial Accounting Standards Board ("FASB") Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143" ("FIN 47").

    The liability recognized under SFAS No. 143 and FIN 47 primarily relates to Oglethorpe's nuclear facilities. Oglethorpe also recognized retirement obligations for ash ponds, landfill sites and asbestos removal.

    Under SFAS No. 71, Oglethorpe may record an offsetting regulatory asset or liability to reflect the difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes for both the cumulative effect of adoption and for future periods timing differences. RUS has approved Oglethorpe's implementation of the provisions of SFAS No. 71 with respect to the cumulative effect of adoption and with respect to timing differences between cost recognition under SFAS No. 143 or Interpretation No. 47 and cost recovery for ratemaking purposes. Therefore, Oglethorpe had no cumulative effect to net margin resulting from the adoption of Statement No. 143 or Interpretation No. 47. Oglethorpe estimates an annual decrease of approximately $3,000,000 over the next several years of the regulatory asset.

    SFAS No. 143 does not permit non-regulated entities to continue accruing future retirement costs associated with long-lived assets for which there are no legal obligations to retire. Oglethorpe, in accordance with regulatory treatment of these costs, continues to recognize the retirement costs for these other obligations in depreciation rates. These costs are reflected on the balance sheet as "Accumulated retirement costs for other obligations" under the caption "Deferred credits and other liabilities."

    In December 2006, GPC provided Oglethorpe with revised asset retirement obligations studies associated with decommissioning at its nuclear plants. These 2006 studies were based on the completed plant decommissioning cost estimates and were in accordance with the standards defined in SFAS No. 143.

    The following table reflects the details of the Asset Retirement Obligations included in the balance sheets.

		(dollars in thousands)
		Balance at 12/31/06		Liabilities Incurred (settled)			Accretion		Balance at 12/31/07
Nuclear decommissioning	$	240,793	$	–		$	15,615	$	256,408
Other		8,782		(418	)		554		8,918
Total	$	249,575	$	(418	)	$	16,169	$	265,326

    As previously discussed, Oglethorpe is deferring the timing differences between cost recognition under SFAS No. 143 and cost recovery for rate making. For 2007 and 2006, these timing differences resulted in a decrease to the regulatory liability of $3,159,000 and $4,581,000, respectively. Increases and decreases to the regulatory liability are reflected on the accompanying balance sheets as "Deferred liability associated with retirement obligations" under the caption "Deferred credits and other liabilities."

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

j. Nuclear decommissioning trust fund

    The Nuclear Regulatory Commission ("NRC") requires all licensees operating commercial power reactors to establish a plan for providing, with reasonable assurance, funds for decommissioning. Oglethorpe has established external trust funds to comply with the NRC's regulations. The funds set aside

59

for decommissioning are managed and invested in accordance with applicable requirements of Oglethorpe's Board of Directors and the NRC. Funds are invested in a diversified mix of equity and fixed income securities. At December 31, 2007 and 2006, equity securities comprised 51% and 50% of the external funds and fixed income securities comprised 49% and 50%, respectively. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. Oglethorpe has filed plans with the NRC to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. Oglethorpe also maintains internal reserves that can be transferred to the external trust fund as needed. All realized gains (losses) and earned income associated with the nuclear decommissioning fund are reflected within the "Cash flows from operating activities" section of Oglethorpe's cash flow statement. Purchases, including reinvestments of earned income, and sales are reflected in the 'Activity in decommissioning fund' line of the "Cash flows from investing activities" section of the cash flow statement. For the periods ending December 31, 2007 and 2006, realized gains (losses) and earned income totaled $18,870,000 and $22,451,000, respectively.

    Nuclear decommissioning cost estimates are based on site studies and assume prompt dismantlement and removal of both the radiated and non-radiated portions of the plant from service. Actual decommissioning costs may vary from these estimates because of changes in the assumed date of decommissioning, changes in regulatory requirements, changes in technology, and changes in costs of labor, materials and equipment. Information with respect to Oglethorpe's portion of the estimated costs of decommissioning co-owned nuclear facilities is as follows:

		(dollars in thousands)
		Hatch Unit No. 1		Hatch Unit No. 2		Vogtle Unit No. 1		Vogtle Unit No. 2
Year of site study		2006		2006		2006		2006
Expected start date of decommissioning		2034		2038		2027		2029
Estimated costs based on site study:
In year 2006 dollars	$	154,000	$	199,000	$	160,000	$	198,000

    Oglethorpe has not recorded any provision for decommissioning during the years 2007, 2006 and 2005 because the balance in the decommissioning trust fund at December 31, 2007 is expected to be sufficient to fund the nuclear decommissioning obligation in future years. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.9%. Oglethorpe assumes a 7.0% earnings rate for its decommissioning trust fund assets. Since inception (1990), the nuclear decommissioning trust fund has produced a return in excess of 8.0%. Oglethorpe's management believes that any increase in cost estimates of decommissioning can be recovered in future rates.

k. Depreciation

    Depreciation is computed on additions when they are placed in service using the composite straight-line method. Annual depreciation rates, as approved by the RUS, in effect in 2007, 2006 and 2005 were as follows:

	Range of Useful Life in years*	2007	2006	2005
Steam production	49-55	1.47%	1.47%	1.97%
Nuclear production	37-52	2.42%	2.44%	2.54%
Hydro production	50	2.00%	2.00%	2.00%
Other production	27-33	3.00%	3.03%	3.03%
Transmission	36	2.75%	2.75%	2.75%
General	3-50	2.00-33.33%	2.00-33.33%	2.00-33.33%

* Calculated based on the composite depreciation rates in effect for 2007.

    Depreciation expense for the years 2007, 2006 and 2005 was $131,436,000, $156,832,000, and $152,558,000, respectively. In 2007, under the provisions of SFAS No. 71, Oglethorpe began deferring the difference between Plant Vogtle depreciation

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expenses based on the current 40-year operating license versus depreciation expenses based on the applied for 20-year license extension. For further discussion of the depreciation deferral, see Note 1(s).

l. Electric plant

    Electric plant is stated at original cost, which is the cost of the plant when first dedicated to public service, plus the cost of any subsequent additions. Cost includes an allowance for the cost of equity and debt funds used during construction. The cost of equity and debt funds is calculated at the embedded cost of all such funds. For the years ended December 31, 2007, 2006 and 2005, the allowance for funds used during construction ("AFUDC") rates used were 6.24%, 6.21% and 5.96%, respectively.

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

m. Bond, reserve and construction funds

    Bond, reserve and construction funds for pollution control revenue bonds ("PCBs") are maintained as required by Oglethorpe's bond agreements. Bond funds serve as payment clearing accounts, reserve funds maintain amounts equal to the maximum annual debt service of each bond issue and construction funds hold bond proceeds for which construction expenditures have not yet been made. As of December 31, 2007 and 2006, all of the funds were invested in either U.S. Government securities or money market accounts.

n. Cash and cash equivalents

    Oglethorpe considers all temporary cash investments purchased with a maturity of three months or less to be cash equivalents. Temporary cash investments with maturities of more than three months are classified as other short-term investments.

o. Restricted cash

    The balances at December 31, 2007 and 2006, $48,124,000 and $18,312,000, respectively, were utilized in January 2008 and 2007 for payment of principal on certain PCBs, respectively.

p. Inventories

    Oglethorpe maintains inventories of fossil fuels and spare parts for its generation plants. These inventories are stated at weighted average cost on the accompanying balance sheets.

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

    At December 31, 2007 and 2006, fossil fuels inventories were $55,981,000 and $50,553,000, respectively. Inventories for spare parts at December 31, 2007 and 2006 were $93,890,000 and $85,443,000, respectively.

q. Deferred charges

    Oglethorpe accounts for both coal-fire outage and nuclear refueling outage costs as deferred outage costs. Beginning in 2006, Oglethorpe began deferring coal-fire outage costs at its fossil fuel facilities, which are accounted for as regulatory assets. The deferral of these costs, are being amortized on a straight-line basis to expense over an 18 to 24 month period. Nuclear refueling outage costs, accounted for as regulatory assets, are deferred and subsequently amortized to expense over the 18-month and 24-month operating cycles of each unit.

    Oglethorpe accounts for debt issuance costs as deferred debt expense. Deferred debt expense is being

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amortized to expense on a straight-line basis over the life of the respective debt issues, which approximates the effective interest rate method.

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

    As of December 31, 2007, the remaining amortization periods for debt inssuance costs and premium and loss on reacquired debt range from approximately 1 to 33 years.

		(dollars in thousands)
		Balance at 12/31/06		Additions		Amortization			Balance at 12/31/07
Outage costs	$	25,782	$	36,551	$	(32,500	)	$	29,833
Debt issuance costs		30,072		9,565		(2,281	)		37,356
Premium (loss) on   reacquired debt		112,147		42,128		(13,446	)		140,829

r. Deferred credits

    As a result of the Rocky Mountain lease transactions, Oglethorpe recorded a net benefit of $95,560,000 which was deferred and is being amortized to income over the 30-year lease-back period. For further discussion on the Rocky Mountain lease transactions, see Note 2.

s. Regulatory assets and liabilities

    Oglethorpe is subject to the provisions of SFAS No. 71. Regulatory assets represent certain costs that are probable of recovery by Oglethorpe from its Members in future revenues through rates under its Wholesale Power Contracts with its Members extending through December 31, 2050. Future revenues are expected to provide for recovery of previously incurred costs and are not calculated to provide for expected levels of similar future costs. Regulatory liabilities represent certain items of income that are being retained by Oglethorpe and that will be applied in the future to reduce revenues required to be recovered from Members.

    The regulatory assets "deferred depreciation expense" and "other regulatory assets" in the table below are included on the balance sheet, under the caption "Deferred charges", in the line item "Other." Derivative instruments below are classified as "Deferred credits and other liabilities" on the balance sheet in the line item "Other." Effective July 1, 2007, Oglethorpe under the provisions of SFAS No. 71 is deferring the difference between Plant Vogtle depreciation expenses based on the current 40-year operating license versus depreciation expenses based on the applied for 20-year license extension. The difference in the depreciation expenses is reflected in the "Deferred depreciation expense" line item in the table below. The deferral amount will be amortized to deprecation expense over the remaining life of Plant Vogtle beginning in the year that the license extension is approved by the NRC. The approval from the NRC is expected mid 2009 or later.

    Oglethorpe's rates are not set to produce revenues that produce a "current return." Oglethorpe operates on a not-for-profit basis. Under Mortgage Indenture requirements Oglethorpe is required to set rates sufficient to achieve net margins that result in a Margin for Interest Ratio of at least 1.10. The current and future amortization of the costs of regulatory assets is considered in determining the revenue requirements necessary to produce a Margin for Interest Ratio of at least 1.10.

    The following regulatory assets and liabilities are reflected on the accompanying balance sheets as of December 31, 2007 and 2006:

		(dollars in thousands)
		2007			2006
Premium and loss on reacquired debt	$	140,829		$	112,147
Deferred amortization of capital leases		91,446			95,450
Deferred outage costs		29,833			25,782
Deferred depreciation expense		14,318			–
Other regulatory assets		1,981			2,401
Derivative instruments		(2,280	)		833
Asset retirement obligations		(5,568	)		(11,085	)
Accumulated retirement costs for other obligations		(53,327	)		(56,220	)
Net benefit of Rocky Mountain transactions		(60,521	)		(63,707	)
Total	$	156,711		$	105,601

    In the event that competitive or other factors result in cost recovery practices under which Oglethorpe can no longer apply the provisions of SFAS No. 71, Oglethorpe would be required to eliminate all regulatory assets and

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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 plant, and write-down those assets, if impaired, to their fair value.

    All of the regulatory assets and liabilities included in the table above are being recovered or refunded to Oglethorpe's Members on a current, ongoing basis in Oglethorpe's rates. The remaining recovery period for the regulatory assets ranges from approximately 1 to 33 years, except for the asset retirement obligations regulatory assets which have a recovery period of 11 to 38.5 years. The remaining refund period for the regulatory liabilities are approximately 19 years for the Rocky Mountain transactions and over the lives of the plants for accumulated retirement costs for other obligations.

t. Other income (expense)

    The components of the other income (expense) line item within the Consolidated Statement of Revenues and Expenses were as follows:

		(dollars in thousands)
		2007		2006		2005
Capital credits from associated companies (Note 2)	$	1,875	$	1,961	$	1,908
Net revenue from Georgia Transmission Corporation ("GTC") & Georgia System Operations Corporation ("GSOC") for shared A&G costs		1,667		1,496		1,501
Miscellaneous other		693		135		(361	)
Total	$	4,235	$	3,592	$	3,048

u. Presentation

    Certain prior year amounts have been reclassified to conform with the current year presentation.

v. New accounting pronouncements

    In December 2007, the FASB issued SFAS No. 160, "Noncontrolling Interests in Consolidated Financial Statements – an amendment to ARB No. 51." The Statement establishes accounting and reporting standards that require: a) ownership interests in subsidiaries be clearly identified and presented in consolidated statement of financial position within equity but separate from parent's equity; b) amount of consolidated net income attributable to parent and noncontrolling interest be present on face of consolidated statement of income; c) changes in parent's ownership interest while controlling financial interest in subsidiary is consistently accounted for; d) retained noncontrolling equity investment in deconsolidated subsidiary be initially measured at fair value; e) sufficient disclosure clearly identifies and distinguish between interests of parent and noncontrolling owners. SFAS No. 160 is effective for Oglethorpe January 1, 2009. Currently, the adoption of SFAS No. 160 is not expected to have any impact on Oglethorpe's results of operations or financial condition.

    In December 2007, the FASB issued SFAS No. 141 (revised 2007), "Business Combinations." The Statement establishes principles and requirements for how the acquirer in a business combination: a) recognizes and measures the identifiable assets acquired, liabilities assumed, and noncontrolling interest in acquiree; b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; c) determines what information to disclose to enable users of financial statements to evaluate the nature and financial effects of the business combination. SFAS No. 141 (revised 2007) is effective for Oglethorpe January 1, 2009. Currently, the adoption of SFAS No. 141 (revised 2007) is not expected to have any impact on Oglethorpe's results of operations or financial condition.

    In February 2007, the FASB issued SFAS No. 159, "The Fair Value Option for Financial Assets and Financial Liabilities", including an amendment of SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities." This statement permits entities to choose to measure many financial instruments and certain other items at fair value that are not currently required to be measured at fair value. This statement also establishes presentation and disclosure requirements designed to facilitate comparison between entities that choose different measurement attributes for similar types of assets and liabilities. The statement provides entities with the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The provisions of this Statement apply only to entities that elect the fair

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value option however, the amendment to SFAS No. 115 applies to all entities with available-for-sale and trading securities. SFAS No. 159 is effective for Oglethorpe January 1, 2008. Oglethorpe will not elect the fair value option for any of its assets, except for assets accounted for under SFAS No. 115.

    In September 2006, the FASB issued SFAS No. 157, "Fair Value Measurements" which defines fair value, establishes a framework for measuring fair value in generally accepted accounting principles (GAAP), and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements. However, the application of SFAS No. 157 may change the current practice for measuring fair value. Oglethorpe adopted SFAS No. 157 effective January 1, 2008 with no material effect on its results of operations or financial condition.

2. Fair value of financial instruments:

    A detail of the estimated fair values of Oglethorpe's financial instruments as of December 31, 2007 and 2006 is as follows:

			(dollars in thousands)
			2007					2006
			Cost		Fair Value			Cost		Fair Value
Long-term investments:
	Auction rate securities	$	47,000	$	47,000		$	61,025	$	61,025
	Equity securities		24,117		28,326			23,560		26,220
	Bonds		33,062		33,447			29,796		29,578
	Other		397		397			1,458		1,458
Total		$	104,576	$	109,170		$	115,839	$	118,281
Bond, reserve and construction funds:
	U. S. Government securities	$	–	$	–		$	5,413	$	5,310
	Money market accounts		5,614		5,614			1,087		1,087
Total		$	5,614	$	5,614		$	6,500	$	6,397
Decommissioning fund:
	U. S. Government securities	$	15,354	$	15,626		$	19,677	$	19,599
	Corporate bonds		63,781		61,473			77,971		77,624
	Commercial paper		–		–			212		215
	Real estate		150		161			150		162
	Equity securities		118,806		123,277			104,034		117,180
	Asset-backed securities		4,716		4,502			9,152		9,134
	Other bonds		29,486		28,872			5,732		5,719
	Cash and money market securities		6,063		6,063			3,676		3,676
Total		$	238,356	$	239,974		$	220,604	$	233,309
Long-term debt		$	3,291,424	$	3,503,861		$	3,197,478	$	3,354,257
Interest rate swaps		$	–	$	(30,526	)	$	–	$	(29,417	)

    Oglethorpe uses the methods and assumptions described below to estimate the fair value of each class of financial instruments. For cash and cash equivalents, restricted cash and receivables the carrying amount approximates fair value because of the short-term maturity of those instruments. The fair value of debt and equity securities are based on the quoted market prices for the same issues. The fair value of Oglethorpe's long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to Oglethorpe for debt of similar maturities. The fair value of the interest rate

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swap arrangements represents a mark-to-market estimate provided by the swap counterparty based on market levels at the close of business on December 31, 2007.

Derivative instruments

    Oglethorpe accounts for derivatives under SFAS No. 133 as amended. The standard establishes accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of certain derivatives as assets or liabilities on Oglethorpe's balance sheet and measurement of those instruments at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is classified as a hedge and if so, the type of hedge.

    In 1993, Oglethorpe entered into two interest rate swap arrangements with AIG Financial Products Corp. ("AIG-FP"), for the purpose of securing a fixed rate lower than otherwise would have been available to Oglethorpe had it issued fixed rate bonds at that time. Under these swap arrangements, Oglethorpe made payments to the counterparty based on the notional principal at a contractual fixed rate and the counterparty made payments to Oglethorpe based on the notional principal at the existing variable rate of the refunding bonds. The differential paid or received was accrued as interest rates changed and was recognized as an adjustment to interest expense. For the Series 1993A notes, the notional principal at December 31, 2007 was $164,515,000 and the fixed swap rate was 5.67% (the variable rate at December 31, 2007 and 2006 was 3.52% and 3.93%, respectively). With respect to the Series 1994A notes, the notional principal at December 31, 2007 was $102,620,000 and the fixed swap rate was 6.01% (the variable rate at December 31, 2007 and 2006 was 3.43% and 3.95%, respectively). The notional principal amount was used to measure the amount of the swap payments and did not represent additional principal due to the counterparty.

    A portion (16.86%) of the AIG-FP interest rate swap arrangements were assumed by GTC in connection with a corporate restructuring. Oglethorpe classified its portion of the two interest rate swap arrangements, pursuant to SFAS No. 133, as cash flow hedges. Oglethorpe's portion of the estimated fair value of the swap arrangements at December 31, 2007 was an unrealized loss of $32,806,000 representing the estimated payment Oglethorpe would have paid if the swap arrangements were terminated. In March 2008, Oglethorpe terminated the AIG-FP swaps. The termination payment to AIG-FP of $36,611,000 has been recorded as a regulatory asset in accordance with SFAS No. 71 and will be amortized to expense over the remaining life of the Series 1993A notes and Series 1994A notes, or 2016 and 2019, respectively.

    Oglethorpe entered into swap arrangements with JPMorgan Chase Bank ("JPMC") in 2006. These swaps use as notional principal, Oglethorpe's 83.14% share of the Series 1993A and Series 1994A bonds ($136,771,000 and $85,314,000 respectively at December 31, 2007) and are designed to convert the contractual variable rate of interest Oglethorpe received under the swaps with AIG-FP to a longer-term contractual variable rate of interest Oglethorpe received from JPMC. The estimated fair value of the JPMC swap arrangements at December 31, 2007 was an unrealized gain of $2,280,000, representing the estimated payment Oglethorpe would have received if the swap arrangements were terminated on that date. In March 2008, Oglethorpe terminated the JPMC swaps. The termination payment received from JPMC of $2,840,000 has been recorded as a regulatory liability in accordance with SFAS No. 71 and will be amortized to expense over the remaining life of the Series 1993A notes and Series 1994A notes, or 2016 and 2019, respectively.

    In accordance with SFAS No. 133, Oglethorpe classifies a cash-flow hedge as a hedge of an exposure to variability in cash flows that are attributable to a particular risk. There are numerous prescriptive criteria that must be met in order for a hedging relationship to qualify as a cash-flow hedge. Some of the criteria are as follows:

    At inception of the hedge, there is formal documentation of the hedging relationship and the entity's risk-management objective and strategy for undertaking the hedge, including identification of the hedging instrument, the hedged cash-flow transaction, the nature of the risk that is being hedged, and how the hedging instrument's effectiveness will be assessed.

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There must be a reasonable basis for how the entity plans to assess the hedging instrument's effectiveness.

    Both at the inception of the hedge and on an on-going basis, the hedging relationship is expected to be highly effective in offsetting the variability of cash flows that are attributable to the hedged risk during the term of the hedge.

    The forecasted transaction is specifically identified as a single transaction or a series of individual transactions. If aggregated, the individual transactions must share the same risk exposure for which they are designated as being hedged.

    The occurrence of the forecasted transaction is probable.

    The forecasted transaction presents an exposure to variations in cash flows for the hedged risk, which could affect reported earnings.

    Settlement amounts related to cash flow hedges are reclassified from other comprehensive margin ("OCM") and recorded in the Statement of Revenues and Expenses when the hedged item affects margins, in the same accounts as the item being hedged. Oglethorpe will discontinue hedge accounting prospectively if it determines that the derivative no longer qualifies as an effective hedge, or if it is no longer probable that the hedged transaction will occur. If hedge accounting is discontinued because the derivative no longer qualifies as an effective hedge, the derivative will continue to be carried on the balance sheet at its fair value, with subsequent changes in its fair value recognized in current-period margins. Gains and losses related to discontinued hedges that were previously accumulated in OCM will remain in OCM until the hedged item is reflected in margin, unless it is no longer probable that the hedged transaction would occur. Gains and losses that were accumulated in OCM will be immediately recognized in current-period margins if it is no longer probable that the hedged transaction will occur.

    As of December 31, 2007, the amount of after-tax deferred losses in OCM that are expected to be reclassified to margins during the next 12 months as the hedged interest payments occur are expected to be immaterial.

    Oglethorpe may be exposed to losses in the event of nonperformance of the counterparties to its derivative instruments, but does not anticipate such nonperformance.

    All activities associated with derivative instruments are included as a component of cash flows from operating activities in Oglethorpe's consolidated statements of cash flows when realized.

Investments in debt and equity securities

    Under SFAS No. 115, "Accounting for Certain Investments in Debt and Equity Securities," investment securities held by Oglethorpe are classified as either available-for-sale or held-to-maturity. Available-for-sale securities are carried at market value with unrealized gains and losses, net of any tax effect, added to or deducted from patronage capital. Unrealized gains and losses from investment securities held in the decommissioning fund, which are also classified as available-for-sale, are directly added to or deducted from deferred asset retirement obligations costs. Held-to-maturity securities are carried at cost. There were no held-to-maturity securities as of December 31, 2007 and 2006. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 44% of these gross unrealized losses were in effect for less than one year. These losses were primarily due to investments in fixed income securities held in the nuclear decommissioning fund. Consistent with Oglethorpe's ratemaking, unrealized gains and losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset.

    Oglethorpe also had $47 million invested in auction rate securities of other companies at December 31, 2007. These securities have maturities in excess of one year and as such are classified as long-term investments. Auction rate securities re-price in Dutch auctions that occur every 7 to 35 days, and Oglethorpe can seek to liquidate these securities at the end of any auction period. Recently, however, Oglethorpe has experienced failed auctions on some of its auction rate securities investments, requiring Oglethorpe to hold the investment during the subsequent auction period. Auction rate securities held for investment by Oglethorpe have AA and AAA credit ratings. Oglethorpe was not expecting

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the current lack of marketability when it made the decision to invest in the securities, but believes that as of December 31, 2007, there was no impairment to auction rates securities.

    The following table summarizes the unrealized gains and losses on the available-for-sale investments as of December 31, 2007 and 2006:

		(dollars in thousands)
		As of December 31,
		2007			2006
Gross unrealized gains	$	17,044		$	19,102
Gross unrealized losses		(10,832	)		(4,058	)

    For those securities considered to be available-for-sale, the following table summarizes the activities for those securities as of December 31:

		(dollars in thousands)
		Gross Unrealized
2007		Cost		Gains		Losses			Fair Value
Equity	$	142,923	$	14,785	$	(6,105	)	$	151,603
Debt		193,399		2,248		(4,727	)		190,920
Other		12,224		11		–			12,235
Total	$	348,546	$	17,044	$	(10,832	)	$	354,758
		Gross Unrealized
2006		Cost		Gains		Losses			Fair Value
Equity	$	127,594	$	17,229	$	(1,423	)	$	143,400
Debt		211,311		1,858		(2,635	)		210,534
Other		4,038		15		–			4,053
Total	$	342,943	$	19,102	$	(4,058	)	$	357,987

    All of the available-for-sale investments are marked to market in the accompanying balance sheets, therefore, the carrying value equals the fair value.

    The contractual maturities of debt securities available-for-sale, which are included in the estimated fair value table above, at December 31, 2007 and 2006 are as follows:

		(dollars in thousands)
		2007				2006
		Cost		Fair Value		Cost		Fair Value
Due within one year	$	22,645	$	22,022	$	42,317	$	41,910
Due after one year through five years		59,544		58,688		53,163		52,994
Due after five years through ten years		8,787		8,749		9,282		9,381
Due after ten years		102,423		101,461		106,549		106,249
Total	$	193,399	$	190,920	$	211,311	$	210,534

    The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2007, 2006 and 2005:

		(dollars in thousands)
		For the years ended December 31,
		2007			2006			2005
Gross realized gains	$	15,492		$	20,491		$	11,366
Gross realized losses		(6,882	)		(7,502	)		(4,010	)
Proceeds from sales		533,334			727,454			678,862

Investment in associated companies, at cost

    Investments in associated companies were as follows at December 31, 2007 and 2006:

		(dollars in thousands)
		2007		2006
National Rural Utilities Cooperative Finance Corp. ("CFC")	$	13,977	$	13,977
CoBank, ACB		4,070		4,288
CT Parts, LLC		5,928		5,924
Georgia Transmission Corporation ("GTC")		13,100		11,682
Georgia System Operations Corporation ("GSOC")		8,214		6,305
Other		1,160		1,155
Total	$	46,449	$	43,331

    The CFC investments are primarily in the form of capital term certificates and are required in conjunction with Oglethorpe's membership in CFC. Accordingly, there is no market for these investments. The investments in CoBank and GTC represent capital credits. Any distributions of capital credits are subject to the discretion of the Board of Directors of CoBank and GTC. The investments in GSOC represent loan advances. The loan repayment schedule ends in December 2013.

    CT Parts, LLC is an affiliated organization formed by Oglethorpe and Smarr EMC for the purpose of purchasing and maintaining a spare parts inventory and administration of contracted services for combustion turbine generation facilities. Such investment is recorded at cost.

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Rocky Mountain transactions

    In December 1996 and January 1997, Oglethorpe entered into six long-term lease transactions for its 74.61% undivided interest in Rocky Mountain pumped storage hydro facility ("Rocky Mountain"), through a wholly owned subsidiary of Oglethorpe, Rocky Mountain Leasing Corporation ("RMLC"). RMLC leases from six owner trusts the undivided interest in Rocky Mountain and subleases it back to Oglethorpe. The Deposit on Rocky Mountain transactions, which is carried at cost, was made in connection with these lease transactions and is invested in a guaranteed investment contract which will be held to maturity (the end of the 30-year lease-back period). At the end of the base lease term, Oglethorpe intends, through RMLC, to repurchase tax ownership and to retain all other rights of ownership with respect to the facility if it is advantageous to do so. If Oglethorpe does elect to repurchase the facility, the funds in the guaranteed investment contract will be used to pay a portion ($371,850,000) of the fixed purchase price.

    In addition, from the proceeds of the Rocky Mountain lease transactions, RMLC paid $640,611,000 to fund payment undertaking agreements with a third party financial institution whose senior debt obligations are rated "AAA" by S&P and "Aaa" by Moody's. In return, this financial institution undertook to pay all of RMLC's periodic basic rent payments under the leases and to pay the remaining portion of the fixed purchase price ($714,923,000) should Oglethorpe, through RMLC, elect to repurchase the facility at the end of the base lease term. Both RMLC's interest in this payment undertaking agreement and the corresponding lease obligations have been extinguished for financial reporting purposes. In 2008, RMLC will be required to make basic rent payments totaling $53,838,000 to the owner trusts. RMLC remains liable for all payments of basic rent under the leases if the payment undertaker fails to make such payments, although the owner trusts have agreed to use due diligence to pursue the payment undertaker before pursuing payment from RMLC or Oglethorpe. The fair value amount relating to the guarantee of basic rent payments is immaterial principally due to the high credit rating of the payment undertaker.

    The assets of RMLC are not available to pay creditors of Oglethorpe or its affiliates.

    Provisions in the Rocky Mountain lease transactions could require Oglethorpe to post surety bonds or letters of credit in the amount of $50 million if Oglethorpe fails to maintain at least two "triple-B" ratings on its senior secured debt (if any and if rated) and at least two "triple-B minus" ratings on its senior unsecured debt (if any and if rated) from S&P, Moody's and Fitch, or if it fails to maintain at least $50 million in available liquidity.

3. Income taxes:

    Oglethorpe is a not-for-profit membership corporation subject to federal and state income taxes. As a taxable electric cooperative, Oglethorpe has annually allocated its income and deductions between patronage and non-patronage activities.

    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 was 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 operations and cash flows.

    Oglethorpe accounts for its income taxes pursuant to SFAS No. 109, "Accounting for Income Taxes." SFAS No. 109 requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns.

    There is no income tax provision for the year ended December 31, 2007.

    The difference between the statutory federal income tax rate on income before income taxes and

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Oglethorpe's effective income tax rate is summarized as follows:

	2007		2006		2005
Statutory federal income tax rate	35.0	%	35.0	%	35.0%
Patronage exclusion	(32.3	%)	(34.0	%)	(35.0%)
Tax credits	0.0	%	0.0	%	0.0%
Other	(2.7	%)	(1.0	%)	0.0%
Effective income tax rate	0.0	%	0.0	%	0.0%

    The components of the net deferred tax assets as of December 31, 2007 and 2006 were as follows:

			(dollars in thousands)
			2007			2006
Deferred tax assets
	Net operating losses	$	134,478		$	168,235
	Tax credits (alternative minimum tax and other)		1,848			1,848
			136,326			170,083
	Less: Valuation allowance		(64,326	)		(170,083	)
Net deferred tax assets		$	72,000		$	–
Deferred tax liabilities
	Depreciation	$	–		$	–
			–			–
Net deferred tax liabilities		$	–		$	–

    As of December 31, 2007, Oglethorpe has federal tax net operating loss carryforwards ("NOLs") and alternative minimum tax credits ("AMT") as follows:

			(dollars in thousands)
Expiration Date			Minimum Alternative Tax Credits		Tax Credits		NOLs
	2008	$	–	$	–	$	94,927
	2009		–		–		96,394
	2010		–		–		77,970
	2018		–		–		61,533
	2019		–		–		10,516
	2020		–		–		4,362
	2021		–		–		–
	None		1,848		–		–
		$	1,848	$	–	$	345,702

    The NOL expiration dates start in the year 2008 and end in the year 2021. Due to the tax basis method for allocating patronage and as shown by the above valuation allowance, it is not likely that the deferred tax assets related to tax credits and NOLs will be realized. The change in the valuation allowance from 2006 to 2007 was the result of the reduction in deferred tax assets due to the expiration of tax credits, net operating losses and the implementation of FIN 48. It is not likely that the remaining AMT credit will be realized.

    In July 2006, the FASB issued Financial Interpretation No. 48, "Accounting for Uncertainty in Income Taxes – an Interpretation of Financial Accounting Standards No. 109 Positions" (FIN 48). The interpretation addresses the determination of whether tax benefits claimed or expected to be claimed on a tax return should be recorded in the financial statements. Under FIN 48, Oglethorpe may recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based on the technical merits of the position. The tax benefits recognized in the financial statements from such a position should be measured based on the largest benefit that has a greater than fifty percent likelihood of being realized upon ultimate settlement. FIN 48 also provides guidance on derecognition, classification, interest and penalties on income taxes, accounting in interim periods and requires increased disclosures. Oglethorpe adopted the provisions of FIN 48 effective January 1, 2007.

    Oglethorpe and its subsidiaries file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year 2004 forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2004 forward.

    As a result of the adoption of FIN 48, Oglethorpe recognized a $96 million increase in the liability for unrecognized tax benefits. This change in the liability resulted in no decrease to the January 1, 2007 balance of patronage capital as the effects were offset by recognition of deferred tax assets. During the third quarter of 2007, one of the four open years expired. Accordingly, this liability and related deferred tax asset was reduced by $24 million during the third quarter.

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Oglethorpe is carrying forward significant regular tax and alternative minimum tax (AMT) net operating losses (NOLs). Therefore, any regular tax liability in the open years related to the uncertain tax position would be offset by regular NOLs. However, Oglethorpe would be liable for the portion of AMT for this period that is not allowed to be offset by the AMT NOLs. In the current open years, Oglethorpe's exposure is not material to its consolidated results of operations, cash flows or financial position.

    Oglethorpe recognizes accrued interest with uncertain tax positions in interest expense in the condensed statements of revenues and expenses. As of December 31, 2007, Oglethorpe has recorded approximately $549,440 for interest in the accompanying balance sheet. It is expected that the amount of unrecognized tax benefits will change in the next twelve months; however, Oglethorpe does not expect the change to have a significant impact on its results of operations, its financial position or its effective tax rate.

    The unrecognized tax benefit reconciliation from beginning balance to ending balance is as follows:

			(dollars in thousands)
Unrecognized tax benefit at beginning of year (January 1, 2007)		$	96,000
	Reduction of tax positions as a result of statue of limitation expiration		(24,000	)
Unrecognized tax benefits at year end (December 31, 2007)		$	72,000

4. Capital leases:

    In 1985, Oglethorpe sold and subsequently leased back from four purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The gain from the sale is being amortized over the 36-year term of the leases.

    In 2000, Oglethorpe entered into a power purchase and sale agreement with Doyle I, LLC ("Doyle Agreement") to purchase all of the output from a five-unit generation facility ("Doyle") for a period of 15 years. Oglethorpe has the option to purchase Doyle at the end of the 15 year term for $10,000,000, which is considered a bargain purchase price.

    The minimum lease payments under the capital leases together with the present value of the net minimum lease payments as of December 31, 2007 are as follows:

Year Ending December 31,			(dollars in thousands)
			Scherer Unit No. 2			Doyle			Total
	2008	$	31,897		$	12,447		$	44,344
	2009		31,882			12,447			44,329
	2010		31,860			12,447			44,307
	2011		31,859			12,447			44,306
	2012		31,772			12,447			44,219
	2013-2021		154,703			43,191			197,894
Total minimum lease payments			313,973			105,426			419,399
	Less: Amount representing interest		(109,903	)		(22,767	)		(132,670	)
	Present value of net minimum lease payments		204,070			82,659			286,729
	Less: Current portion		(18,090	)		(7,696	)		(25,786	)
	Long-term balance	$	185,980		$	74,963		$	260,943

    The interest rate on the Scherer No. 2 lease obligation is 6.97%. For Doyle, the lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00%. At December 31, 2007, the weighted average interest rate on the Doyle lease obligation was 5.95%.

    The Scherer No. 2 lease and the Doyle Agreement meet the definitional criteria to be reported as capital leases. For rate-making purposes, however, Oglethorpe includes the actual lease payments in its cost of service. The difference between lease payments and the aggregate of the amortization on the capital lease asset and the interest on the capital lease obligation is recognized as a regulatory asset on the balance sheet pursuant to SFAS No. 71.

5. Long-term debt:

    Long-term debt consists of mortgage notes payable to the United States of America acting through the FFB and the RUS, mortgage bonds payable, mortgage notes issued in conjunction with the sale by public authorities of PCBs, and mortgage notes payable to CoBank. Substantially all of the owned tangible and certain of the intangible assets of Oglethorpe are pledged as collateral for the FFB and RUS notes, the mortgage

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bonds, the CoBank mortgage notes and the mortgage notes issued in conjunction with the sale of PCBs.

    In October 2007, Oglethorpe issued $500,000,000 of first mortgage bonds and used the proceeds to prepay $442,000,000 of existing FFB debt and for general corporate purposes. Redemptions on the new fixed rate debt occur in 2024 to 2030 with a final maturity of 2031.

    Also in October 2007, Oglethorpe completed a refunding transaction whereby $181,890,000 of PCBs were issued. The proceeds were used to make PCB principal payments in the amount of $21,715,000 due on January 1, 2008 and to refinance $160,180,000 of PCB bullet maturities. The PCBs were refinanced for the purpose of extending the maturity dates on the debt, which are now scheduled to mature in 2038 through 2040.

    In conjunction with the payment of PCB principal due on January 1, 2008, $1,076,000 was released from a debt service reserve fund and applied to the payment of principal and interest due on the bonds being refunded.

    In connection with a 1997 corporate restructuring, 16.86% of the then outstanding PCBs were assumed by GTC, including approximately $3,662,000 of the PCBs that were refinanced in October 2007. As it has the right to do so pursuant to an agreement between the companies, GTC participated in the refinancing and assumed an obligation for $3,662,000 of the PCB refunding debt issued in October 2007.

    The annual interest requirement for 2008 is estimated to be $223,038,000.

    Maturities for long-term debt and amortization of the capital lease obligations through 2012 are as follows:

		(dollars in thousands)
		2008		2009		2010		2011		2012
FFB	$	68,578	$	71,969	$	74,289	$	77,837	$	81,513
RUS		603		634		666		700		736
CoBank		305		344		387		435		490
PCBs (1)		48,128		13,414		32,215		36,268		33,674
		117,614		86,361		107,557		115,240		116,413
Capital leases (2)		25,786		24,876		27,121		29,657		32,508
Total	$	143,400	$	111,237	$	134,678	$	144,897	$	148,921

(1)

Amounts reflect only Oglethorpe's 83.14% share of the PCB maturities. The 2008 maturities were refinanced in an October 2007 transaction, and a plan is in place to refinance all future PCB annual maturities in the 4th quarter of the year prior to maturity.

(2)

Amounts reflect the debt portion of annual amortization of capitalized lease obligations as reflected on the balance sheet.

    The weighted average interest rate for long-term debt and capital leases was 5.45% at December 31, 2007.

    Oglethorpe has a $50,000,000 committed line of credit with CFC and another $50,000,000 committed line of credit with CoBank. Both of these credit facilities are for general working capital purposes. No balance was outstanding on either of these two lines of credit at either December 31, 2007 or 2006.

    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 lines of credit, thereby providing 100% dedicated support for any paper outstanding. Oglethorpe periodically assesses its needs to determine the appropriate amount to maintain in its backup facility, and currently has in place a $450,000,000 committed backup line of credit that expires in July 2012. In addition to providing dedicated support for commercial paper, the facility may also be used for working capital and for general corporate purposes and to issue letters of credit in an aggregate amount up to $50,000,000. However, any amounts drawn under the facility for working capital or general purposes or for purposes of supporting issued letters of credit will reduce the amount of commercial paper that Oglethorpe is authorized to issue. No balance was outstanding on this line of credit at either December 31, 2007 or 2006.

6. Electric plant and related agreements:

    Oglethorpe and GPC have entered into agreements providing for the purchase and subsequent joint

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operation of certain of GPC's electric generating plants. The plant investments disclosed in the table below represent Oglethorpe's undivided interest in each co-owned plant, and each co-owner is responsible for providing its own financing. A summary of Oglethorpe's plant investments and related accumulated depreciation as of December 31, 2007 is as follows:

				(dollars in thousands)
Plant				Investment		Accumulated Depreciation
In-service
	Owned property
		Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership)	$	2,728,456	$	(1,366,024	)
		Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership)		584,815		(333,472	)
		Wansley Units No. 1 & No. 2 (Fossil – 30% ownership)		233,685		(109,397	)
		Scherer Unit No. 1 (Fossil – 60% ownership)		487,814		(248,394	)
		Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 75% ownership)		557,367		(139,971	)
		Talbot (Combustion Turbine – 100% ownership)		279,046		(44,203	)
		Chattahoochee (Combined cycle – 100% ownership)		296,782		(43,377	)
		Wansley (Combustion Turbine – 30% ownership)		3,606		(2,541	)
		Transmission plant		63,107		(35,454	)
		Other		88,957		(45,754	)
Property under capital lease:
		Plant Doyle (Combustion Turbine – 100% leasehold)		126,990		(62,582	)
		Scherer Unit No. 2 (Fossil – 60% leasehold)		341,851		(199,353	)
Total in-service			$	5,792,476	$	(2,630,522	)
Construction work in progress
	Generation improvements		$	188,863
	Other			239
Total construction work in progress			$	189,102

    Oglethorpe's proportionate share of direct expenses of joint operation of the above plants is included in the corresponding operating expense captions (e.g., fuel, production or depreciation) on the accompanying statements of revenues and expenses.

    Oglethorpe has the option to participate in up to 30% of up to two additional nuclear units at Plant Vogtle. Oglethorpe is currently participating in 30% of the development costs, with the option to reduce participation, either partially or completely. As of December 31, 2007, the total capitalized costs to date were $18,402,000.

7. Employee benefit plans:

    Effective January 1, 2005 Oglethorpe merged its money purchase pension plan and its contributory 401(k) plan into one plan the OPC Retirement Plan. The merged plan is a 401(k) plan. The money purchase pension feature of the merged plan is now known as the employer retirement contribution. Under the merged plan, in 2005 and 2006, Oglethorpe contributed 5% subject to IRS limitations of each employee's eligible annual compensation and at its discretion, matched as much as three-quarters of the first 6% of the employee's contribution. Effective 2007, Oglethorpe's contribution is 8% to the employer retirement contribution feature.

    Oglethorpe's retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of their eligible annual compensation. Oglethorpe, at its discretion, may match the employee's contribution and has done so each year of the plan's existence. Oglethorpe's current policy is to match the employee's contribution as long as there is sufficient margin to do so. The match, which is calculated each pay period, currently can be equal to as much as three-quarters of the first 6% of an employee's eligible compensation, depending on the amount and timing of the employee's contribution. Oglethorpe's contributions to the matching feature of the plan were approximately $665,000 in 2007, $644,000 in 2006 and $630,000 in 2005. Oglethorpe's contributions to the employer retirement contribution feature of the 401(k) plan were approximately $1,300,000 in 2007, $775,000 in 2006 and $758,000 in 2005.

8. Nuclear insurance:

    GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, is a member of Nuclear Electric Insurance, Ltd. ("NEIL"), a mutual insurer established to provide property damage insurance coverage in an amount up to $500,000,000 for members' nuclear generating facilities. In the event that losses exceed accumulated reserve funds, the members are subject to retroactive assessments (in proportion to their

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premiums). The portion of the current maximum annual assessment for GPC that would be payable by Oglethorpe, based on ownership share, is limited to approximately $8,627,000 for each nuclear incident.

    GPC, on behalf of all the co-owners of Plants Hatch and Vogtle, has coverage under NEIL II, which provides insurance to cover decontamination, debris removal and premature decommissioning as well as excess property damage to nuclear generating facilities for an additional $2,250,000,000 for losses in excess of the $500,000,000 primary coverage described above. Under the NEIL policies, members are subject to retroactive assessments in proportion to their premiums if losses exceed the accumulated funds available to the insurer under the policy. The portion of the current maximum annual assessment for GPC that would be payable by Oglethorpe, based on ownership share, is limited to approximately $10,483,000.

    For all on-site property damage insurance policies for commercial nuclear power plants, the NRC requires that the proceeds of such policies shall be dedicated first for the sole purpose of placing the reactor in a safe and stable condition after an accident. Any remaining proceeds are next to be applied toward the costs of decontamination and debris removal operations ordered by the NRC, and any further remaining proceeds are to be paid either to the company or to its bond trustees as may be appropriate under the policies and applicable trust indentures.

    The Price-Anderson Act, as amended in 1988, limits public liability claims that could arise from a single nuclear incident to $10,761,000,000 which amount is to be covered by private insurance and a mandatory program of deferred premiums that could be assessed against all owners of nuclear power reactors. Such private insurance provided by American Nuclear Insurers ("ANI") (in the amount of $300,000,000 for each plant, the maximum amount currently available) is carried by GPC for the benefit of all the co-owners of Plants Hatch and Vogtle. Agreements of indemnity have been entered into by and between each of the co-owners and the NRC. In the event of a nuclear incident involving any commercial nuclear facility in the country involving total public liability in excess of $300,000,000, a licensee of a nuclear power plant could be assessed a deferred premium of up to $100,590,000 per incident for each licensed reactor operated by it, but not more than $15,000,000 per reactor per incident to be paid in a calendar year. On the basis of its ownership interest in four nuclear reactors, Oglethorpe could be assessed a maximum of $120,708,000 per incident, but not more than $18,000,000 in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due on or before August 31, 2008.

    All retrospective assessments, whether generated for liability or property, may be subject to applicable state premium taxes.

    Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3.24 billion plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

9. Commitments:

a. Power purchase and sale agreements

    Oglethorpe has entered into long-term power purchase agreements. As of December 31, 2007, Oglethorpe's minimum purchase commitment under these agreements, without regard to capacity reductions or adjustments for changes in costs, for the next five years and thereafter are as follows:

Year Ending December 31,			(dollars in thousands)
	2008	$	76,516
	2009		28,417
	2010		28,759
	2011		29,104
	2012		29,453
	Thereafter		216,308

    Oglethorpe's power purchases from these agreements amounted to approximately $89,244,000 in 2007, $102,646,000 in 2006 and $163,122,000 in 2005.

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b. Operating leases

    As of December 31, 2007, Oglethorpe's estimated minimum rental commitments for these operating leases over the next five years and thereafter are as follows:

Year Ending December 31,			(dollars in thousands)
	2008	$	4,932
	2009		4,832
	2010		5,086
	2011		5,420
	2012		5,817
	Thereafter		32,041

    Rental expenses totaled $5,299,000 in 2007, $5,227,000 in 2006 and $5,252,000 in 2005. The rental expenses for the leases are added to the cost of the fossil inventories.

10. Sale of emission allowances

    The Clean Air Act Amendments of 1990 established SO₂ allowances to manage the achievement of SO₂ emissions requirements. The legislation also established a market-based SO₂ allowance trading component.

    An allowance authorizes a utility to emit one ton of SO₂ during a given year. The Environmental Protection Agency ("EPA") allocates allowances to utilities based on mandated emissions reductions. At the end of each year, a utility must hold an amount of allowances at least equal to its annual emissions. Allowances are fully marketable commodities. Once allocated, allowances may be bought, sold, traded, or banked for use in future years. Allowances may not be used for compliance prior to the calendar year for which they are allocated. Oglethorpe accounts for these using an inventory model with a zero basis for those allowances allocated to Oglethorpe and recognizes a gain at the time of sale.

    Over the years, Oglethorpe has acquired allowances through EPA allocations. Also, over time, Oglethorpe has sold excess allowances based on compliance needs and allowances available. Oglethorpe currently receives allowances annually to cover its emissions. This allocation will continue through 2009 and will change beginning in 2010 in accordance with the EPA's SO₂ allowance program.

    During 2007, 2006, and 2005, Oglethorpe sold SO₂ allowances in excess of its needs to various parties and received $0.4 million, $39.5 million, and $83.1 million in proceeds from these sales, respectively. Oglethorpe offset $0.4 million, $29.3 million, and $61.9 million of this income by reducing amounts collected from its Members during 2007, 2006 and 2005, respectively. The remaining $10.2 million of income in 2006 and $21.2 million in 2005 was offset by amortizing $10.2 million and $21.2 million of deferred asset retirement obligations costs. As a result, there was no net change to net margin in 2007, 2006 or 2005.

11. Guarantees:

    As of December 31, 2007 and 2006, Oglethorpe's guarantees included those disclosed in Note 5 for PCBs assumed by GTC in connection with a corporate restructuring and in Note 2 for rental payments due under the terms of the Rocky Mountain transactions. See Note 2 for discussion of Rocky Mountain transactions.

    The amount of the fair value of Oglethorpe's guarantee related to the PCBs assumed by GTC is immaterial due to the small amount of assumed principal outstanding and the high credit rating of GTC.

12. Environmental matters:

    Set forth below are environmental matters that could have an effect on Oglethorpe's financial condition or results of operations. At this time, the resolution of these matters is uncertain, and Oglethorpe has made no accruals for such contingencies and cannot reasonably estimate the possible loss or range of loss with respect to these matters.

a. General

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

    In general, environmental requirements are becoming increasingly stringent. New requirements may substantially increase the cost of electric service by

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requiring changes in the design or operation of existing facilities. Failure to comply with these requirements could result in the imposition of civil and criminal penalties as well as the complete shutdown of individual generating units not in compliance. Certain of our debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current or future environmental laws and regulations. Should we fail to be in compliance with these requirements, it would constitute a default under such debt instruments. Oglethorpe cannot provide assurance that it will always be in compliance with current and future regulations.

b. Clean Air Act

    In January 2003, the Sierra Club appealed an unsuccessful challenge to the air operating permit for the Chattahoochee combined cycle facility to the U.S. Court of Appeals for the Eleventh Circuit. Oglethorpe acquired this facility when it merged with Chattahoochee EMC in May 2003. Oglethorpe intervened in the appeal on behalf of the U.S. Environmental Protection Agency (EPA). In May 2004, the Court ruled in favor of the Sierra Club, invalidating EPA's denial of the petition and remanding the matter to EPA for further consideration. In November 2005, EPA issued an order denying Sierra Club's petition to object to the permit. In January 2006, the Sierra Club filed an appeal of that order to the U.S. Court of Appeals for the Eleventh Circuit. Oglethorpe again intervened in the appeal on behalf of EPA, and on June 26, 2007, the Court ruled in favor of EPA, upholding its decision not to object to the permit. As the time for appeal of the case has run, Sierra Club's challenge to this permit has ended.

    In April 2007, the Sierra Club and the Coosa River Basin Initiative appealed two unsuccessful permit challenges involving operating permit renewals for Plants Scherer (co-owned by Oglethorpe), Bowen, Hammond and Branch to the U.S. Court of Appeals for the Eleventh Circuit. The remaining challenge in the appeal is that the permits for Scherer and Bowen do not include compliance schedules to bring the sources into compliance with Prevention of Significant Deterioration requirements. Oglethorpe filed a motion to intervene on behalf of EPA in the case and that motion was granted. Briefing on the case was completed in December 2007, and oral argument has been scheduled in the case for March 31, 2008. A decision is expected from the Court later in 2008.

13. Ad valorem tax matters:

Monroe County Appeal

    2003 Appeal. On October 28, 2003, the Monroe County Board of Assessors issued its assessment of Oglethorpe's interest in Plant Scherer for the 2003 tax year. While the state valued this interest at $330,538,885, Monroe County's assessment used a valuation of $898,722,327. On December 11, 2003, Oglethorpe appealed Monroe County's valuation by filing a notice of arbitration with the Monroe County Board of Tax Assessors.

    2004 Appeal. On July 8, 2004, the Monroe County Board of Assessors issued its assessment of Oglethorpe's interest in Plant Scherer for the 2004 tax year. While the state valued this interest for the 2004 tax year at $362,685,639, Monroe County's assessment used a valuation of $817,826,084. On August 20, 2004, Oglethorpe appealed Monroe County's valuation by filing a notice of arbitration with the Monroe County Board of Tax Assessors.

    2005 Appeal. On January 4, 2006, the Monroe County Board of Assessors issued its assessment of Oglethorpe's interest in Plant Scherer for the 2005 tax year. While the state valued this interest at $344,902,128, Monroe County's assessment used a valuation of $981,199,888. On February 10, 2006, Oglethorpe appealed Monroe County's valuation by filing a notice of arbitration with the Monroe County Board of Tax Assessors.

    2006 Appeal. On January 3, 2007, the Monroe County Board of Assessors issued its assessment of Oglethorpe's interest in Plant Scherer for the 2006 tax year. While the state valued this interest at $343,262,927, Monroe County's assessment used a valuation of $728,850,596. On January 31, 2007, Oglethorpe appealed Monroe County's valuation by filing a notice of arbitration with the Monroe County Board of Tax Assessors.

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    2007 Appeal. On October 23, 2007, the Monroe County Board of Assessors issued its assessment of Oglethorpe's interest in Plant Scherer for the 2007 tax year. While the state valued this interest at $367,122,431, Monroe County's assessment used a valuation of $728,850,596. On November 29, 2007, Oglethorpe appealed Monroe County's valuation by filing a notice of arbitration with the Monroe County Board of Tax Assessors.

    The arbitrations for all five appeals were on hold pending the outcome of a related case filed by Georgia Power Company (GPC), which challenged the authority of Monroe County to change the values determined by the Georgia Department of Revenue. On January 8, 2008, the Georgia Supreme Court issued its final decision in that related case, holding that Monroe County did not have the authority to increase the values determined by the Georgia Department of Revenue.

    Oglethorpe and Monroe County are now in the process of documenting the final tax amounts for all of the years on appeal as a result of the Georgia Supreme Court's decision in favor of Georgia Power. Oglethorpe and Monroe County previously entered a Settlement Agreement and Release, agreeing that Oglethorpe would not owe any additional taxes for the tax years 2003, 2004, and 2005 if the Georgia Supreme Court decided the case in favor of Georgia Power. For the tax years 2006 and 2007, Oglethorpe has paid Monroe County the tax amounts due based on the state's value determinations. Accordingly, the final documentation should show that Oglethorpe does not owe any additional property taxes to Monroe County for the years 2003 through 2007. Once Oglethorpe receives this final documentation, the five arbitration appeals will be dismissed. As a result of the GPC decision and the contemplated dismissal of the arbitration appeals, there is no longer an amount accrued for Monroe County ad valorem taxes. Previously, the disputed additional taxes accrued were $22.7 million.

14. Subsequent event

    The three major credit rating agencies are in the process of an on-going review of the monoline bond insurers as a result of the exposure some insurers have to financial guarantees provided on structured finance obligations backed by subprime residential mortgages. Several bond insurers have already been downgraded below their historical triple-A rating levels or have had negative outlooks assigned to their triple-A ratings, including three insurers that provide guarantees on a significant portion of Oglethorpe's outstanding variable rate PCB indebtedness.

    Bond insurer downgrades have been most material as it relates to their impact on auction rate securities (ARS) guaranteed by the insurer, leading to increased focus on the underlying issuer credit, wider credit spreads, and failed auctions. A bond insurer downgrade can also affect the credit spread of insured variable rate demand bonds (VRDB), but currently less than ARS due to bank liquidity support on a VRDB which allows bonds to be put to the liquidity facility in the event of a failed remarketing.

    Oglethorpe currently has outstanding $434 million of PCBs in the ARS mode and $410 million of PCBs in the VRDB mode. Oglethorpe has recently seen some of its ARS auctions fail due to investors moving away from this market, and has also had VRDBs put to the supporting bank liquidity facilities due to the remarketing agents' inability to remarket the bonds as a result of a downgrade of the bond insurer. These events have resulted in higher variable rates of interest on the bonds, in some instances as high as 12%. The weighted average interest rate on Oglethorpe's PCBs in the ARS mode was approximately 4% and 7% at December 31, 2007 and March 19, 2008, respectively.

    In light of these events, in a remarketing expected to close in April 2008, Oglethorpe plans to convert $312 million of its PCBs from the ARS mode to another interest rate mode as it has the option to do pursuant to the underlying bond documents. Oglethorpe also plans to refinance the balance of its PCBs in the ARS mode ($123 million) in a transaction that is expected to close in October 2008.

    In a transaction expected to close in May 2008, Oglethorpe expects to refinance $255 million of PCBs that are currently in a weekly VRDB mode (due to a downgrade of the existing bond insurer) through the issuance of $255 million of Series 2008 refunding bonds. While this transaction is being undertaken mainly to replace the bond insurer, this transaction will also provide for an immediate extension of the maturities, rather than over time as the principal on this PCB debt was set to mature each year.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Members of Oglethorpe Power Corporation:

       In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and the related consolidated statements of revenues and expenses, patronage capital and membership fees and accumulated other comprehensive deficit and cash flows present fairly, in all material respects, the financial position of Oglethorpe Power Corporation and its subsidiaries (an Electric Membership Cooperative) at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

       As discussed in Note 3, effective January 1, 2007 the Company changed its method of accounting for uncertain tax positions.

/s/ PricewaterhouseCoopers LLP
Atlanta, Georgia
March 26, 2008

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

    None.

ITEM 9A. CONTROLS AND PROCEDURES

Management's Responsibility for Financial Statements

    The management of Oglethorpe Power Corporation has prepared this report and is responsible for the financial statements and related information. These statements were prepared in accordance with generally accepted accounting principles and necessarily include amounts that are based on best estimates and judgments of management. Financial information throughout this Annual Report on Form 10-K is consistent with the financial statements.

    Management believes that its policies and procedures provide reasonable assurance that Oglethorpe's operations are conducted with a high standard of business ethics. In management's opinion, the financial statements present fairly, in all material respects, the financial position, results of operations, and cash flows of Oglethorpe.

Conclusions Regarding the Effectiveness of Disclosure Controls and Procedures

    Under the supervision and with the participation of Oglethorpe's management, including its principal executive officer and principal financial officer, Oglethorpe conducted an evaluation of its disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated under the Securities Exchange Act of 1934, as amended (the "Exchange Act"). Based on this evaluation, Oglethorpe's principal executive officer and principal financial officer concluded that its disclosure controls and procedures were effective as of December 31, 2007 in providing a reasonable level of assurance that information Oglethorpe's required to disclose in reports that Oglethorpe files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods in SEC rules and forms, including a reasonable level of assurance that information required to be disclosed by Oglethorpe in such reports is accumulated and communicated to its management, including its principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosure.

Management's Report on Internal Control Over Financial Reporting

    Oglethorpe's management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of its management, including its principal executive officer and principal financial officer, Oglethorpe conducted an evaluation of the effectiveness of its internal control over financial reporting based on the framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO").

    Based on Oglethorpe's evaluation under the framework in Internal Control – Integrated Framework issued by COSO, its management concluded that its internal control over financial reporting was effective as of December 31, 2007 in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. This Annual Report on Form 10-K does not include an attestation report of Oglethorpe's registered public accounting firm regarding internal control over financial reporting. Management's report was not subject to attestation by Oglethorpe's registered public accounting firm pursuant to temporary rules of the SEC that permit Oglethorpe to provide only management's report in this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

    There were no changes in Oglethorpe's internal control over financial reporting identified in connection with the above-referenced evaluation by management of the effectiveness of its internal control over financial reporting that occurred during the fourth quarter ended December 31, 2007, that have materially affected, or are reasonably likely to materially affect, its internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION

    Oglethorpe is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Recent changes in securities laws and regulations impose new requirements on SEC filers. Oglethorpe is evaluating these requirements and the related cost of compliance. Preliminary indications are that it may not be cost-justified for Oglethorpe to continue as a voluntary SEC filer. Oglethorpe will monitor changes in these requirements and will continue to evaluate the cost-justification of complying with these requirements.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

    Oglethorpe has a thirteen member Board of Directors consisting of eleven directors elected from the Members (the "Member Directors") and two independent outside directors (the "Outside Directors"). Five of the Member Directors must be a general manager of a Member located in each of five geographical regions of the State of Georgia. An additional five Member Directors must be a director of a Member located in each of five geographical regions of the State of Georgia. The eleventh Member Director must be a director of a Member. A Member may not have both its general manager and one of its directors serve as a Director of Oglethorpe at the same time.

    No person may simultaneously serve as a director of Oglethorpe and either GTC or GSOC, and the Outside Directors may not be a director, officer or employee of GTC, GSOC or any Member or an officer or employee of Oglethorpe. The directors are nominated by representatives from each Member whose weighted nomination is based on the number of retail customers served by each Member, and after nomination, elected by a majority vote of the Members, voting on a one-Member, one-vote basis. The directors serve staggered three-year terms.

    Oglethorpe is managed and operated under the direction of a President and Chief Executive Officer, who is appointed by the Board of Directors. The Executive Officers and Directors of Oglethorpe are as follows:

Name	Age	Position
Executive Officers:
Thomas A. Smith	53	President and Chief Executive Officer
Michael W. Price	47	Chief Operating Officer
Elizabeth B. Higgins	39	Chief Financial Officer
William F. Ussery	43	Senior Vice President, Member and External Relations
W. Clayton Robbins	61	Senior Vice President, Government Relations and Chief Administrative Officer
Jami G. Reusch	45	Vice President, Human Resources
Directors:
Benny W. Denham	77	Chairman of the Board, Member Director, Southwest Region
J. Sam L. Rabun	76	Vice Chairman of the Board, Member Director, Central Region
Larry N. Chadwick	67	Member Director, Northwest Region
Marshall S. Millwood	58	Member Director, Northeast Region
M. Anthony Ham	56	Member Director, Southeast Region
H.B. Wiley, Jr.	63	Member Director, Statewide
Jeffrey W. Murphy	44	Manager Director, Northeast Region
Gary A. Miller	47	Manager Director, Northwest Region
C. Hill Bentley	60	Manager Director, Central Region
Gary W. Wyatt	55	Manager Director, Southwest Region
Wm. Ronald Duffey	66	Outside Director
John S. Ranson	78	Outside Director

Robert E. Rentfrow served on the Board of Directors of Oglethorpe as a Manager Director from the Southeast Region since 2002, but ceased serving as a Director on February 4, 2008.

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Executive Officers

Thomas A. Smith is the President and Chief Executive Officer of Oglethorpe and has served in that capacity since September 1999. He previously served as Senior Vice President and Chief Financial Officer of Oglethorpe from September 1998 to August 1999, Senior Financial Officer from 1997 to August 1998, Vice President, Finance from 1986 to 1990, Manager of Finance from 1983 to 1986 and Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was Senior Vice President of the Rural Utility Banking Group of CoBank, where he managed the bank's eastern division, rural utilities. Mr. Smith is a Certified Public Accountant, has a Master of Science degree in Industrial Management-Finance from the Georgia Institute of Technology, a Master of Science degree in Analytical Chemistry from Purdue University and a Bachelor of Arts degree in Mathematics and Chemistry from Catawba College. Mr. Smith is a Director of ACES Power Marketing, and as Treasurer of the Board, also serves as the Chairman of their Risk Oversight and Audit Committee. He is a Director of the Georgia Chamber of Commerce and is also a member of the Advisory Board of Mid-South Telecommunications, Inc. Mr. Smith previously served as a director of En-Touch Systems, Inc. from 2001-2006 and as a member of the NERC Stakeholders Committee from 2005-2006.

Michael W. Price is the Chief Operating Officer of Oglethorpe and has served in that office since February 1, 2000. Mr. Price was employed by GSOC from January 1999 to January 2000, first as Senior Vice President and then as Chief Operating Officer. He served as Vice President of System Planning and Construction of GTC from May 1997 to December 1998. He served as a manager of system control of GSOC from January to May 1997. From 1986 to 1997, Mr. Price was employed by Oglethorpe in the areas of control room operations, system planning, construction and engineering, and energy management systems. Prior to joining Oglethorpe, he was a field test engineer with the Tennessee Valley Authority from 1983 to 1986. Mr. Price has a Bachelor of Science degree in Electrical Engineering from Auburn University. Mr. Price is a Director of SERC Reliability Corporation, ACES Power Marketing, the Research Advisory Committee of Electric Power Research Institute and serves on the Advisory Board of Garrard Construction.

Elizabeth B. Higgins is the Chief Financial Officer of Oglethorpe and has served in that office since July 2004. Ms. Higgins served as Senior Vice President, Finance & Planning of Oglethorpe from July 2003 to July 2004. Ms. Higgins served as Vice President of Oglethorpe with various responsibilities including strategic planning, rates, analysis and member relations from September 2000 to July 2003. Ms. Higgins served as the Vice President and Assistant to the Chief Executive Officer of Oglethorpe from October 1999 to September 2000 and served in other capacities for Oglethorpe from April 1997 to September 1999. Prior to that, Ms. Higgins served as Project Manager at Southern Engineering from October 1995 to April 1997, as Senior Consultant at Deloitte & Touche, LLP from April 1995 to October 1995, and as Senior Consultant at Energy Management Associates from June 1991 to April 1995. In these positions, Ms. Higgins was responsible for competitive bidding analyses, rate designs, integrated resource planning studies, operational/dispatch studies, bulk power market analysis, merger analyses and litigation support. Ms. Higgins has a Bachelor of Industrial Engineering degree from the Georgia Institute of Technology and a Master of Business Administration degree from Georgia State University.

William F. Ussery is the Senior Vice President, Member and External Relations of Oglethorpe and has served in that office since October 2005. Mr. Ussery previously served as Vice President and Assistant Chief Operating Officer of Oglethorpe from November 2003 to October 2005. Prior to joining Oglethorpe in 2001, Mr. Ussery held several key positions, including Chief Operating Officer, Vice President of Engineering and System Engineer at Sawnee EMC. Mr. Ussery holds a bachelor's degree in Electrical Engineering from Auburn University and an associate degree in Science from Middle Georgia College.

W. Clayton Robbins is the Senior Vice President, Government Relations and Chief Administrative Officer of Oglethorpe and has served in the office since July 2006. Mr. Robbins served as Chief Administrative Officer of Oglethorpe from January 2006 to June 2006; served as Senior Vice President, Administration and Risk Management of Oglethorpe from October 2002 to December 2006; and served as Senior Vice President, Finance and Administration of Oglethorpe from November 1999 to September 2002. Mr. Robbins served as Senior Vice President and General Manager of

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Intellisource, Inc. from February 1997 to October 1999. Prior to that, Mr. Robbins has held several positions at Oglethorpe since 1986, including Senior Vice President, Support Services from December 1991 to January 1997 and Vice President, Market Research and Analysis from December 1989 to November 1991. Before joining Oglethorpe, Mr. Robbins spent 18 years with Stearns-Catalytic World Corporation, a major engineering and construction firm, including 13 years in management positions responsible for human resources, information systems, contracts, insurance, accounting, and project development. Mr. Robbins has a Bachelor of Arts degree in Business Administration from the University of North Carolina at Charlotte. Mr. Robbins serves on the Advisory Board of FM Global Insurance Company and on the Board of Directors of Niner Wine Estates, Paso Robles, California.

Jami G. Reusch is the Vice President, Human Resources and has served in that office since July 2004. Ms. Reusch served as Oglethorpe's Director of Human Resources and held several other management and staff positions in Human Resources prior to July 2004. Prior to joining Oglethorpe in 1994, Ms. Reusch was a senior officer in the banking industry in Georgia, where she held various leadership roles. Ms. Reusch has a Bachelor of Education degree and a Master of Human Resource Development degree from Georgia State University. She also has a Senior Professional in Human Resources certification.

Board of Directors

Benny W. Denham is Chairman of the Board and Member Director from the Southwest Region. He has served on the Board of Directors of Oglethorpe since December 1988. His present term will expire in March 2010. Mr. Denham has been co-owner of Denham Farms in Turner County, Georgia since 1980. Mr. Denham is a Director of Irwin EMC.

J. Sam L. Rabun is the Vice-Chairman of the Board and is the Member Director from the Central Region. He has served on the Board of Directors of Oglethorpe since March 1993. His present term will expire in March 2010. He is also the Chairman of the Compensation Committee. He has been the owner and operator of a farm in Jefferson County, Georgia since 1979. Mr. Rabun served as the President of the Board of Jefferson Energy Cooperative from 1993 to 1996, was employed as General Manager from 1974 to 1979 and as Office Manager and Accountant from 1970 to 1974. He currently serves as Chairman of the Board of Jefferson Energy Cooperative. Mr. Rabun is Vice-Chairman of the Board of the Georgia Energy Cooperative.

Larry N. Chadwick is the Member Director from the Northwest Region. He has served on the Board of Directors of Oglethorpe since July 1989. His present term will expire on March 31, 2008. He is also a member of the Compensation Committee. Mr. Chadwick is an engineer, with experience in the design of hydrogen gas plants. He is Chairman of the Board of Cobb EMC.

Marshall S. Millwood is the Member Director from the Northeast Region. He became a member of the Board of Directors of Oglethorpe in March 2003, and his present term will expire in March 2009. He is also a member of the Audit Committee. He has been the owner and operator of Marjomil Inc., a poultry and cattle farm in Forsyth County, Georgia, since 1998. He is a Director of Sawnee EMC.

M. Anthony Ham is the Member Director from the Southeast Region. He became a member of the Board of Directors of Oglethorpe in March 2004, and his term will expire on March 31, 2008. He is also a member of the Compensation Committee. Mr. Ham is the Clerk of the Superior and Juvenile Courts in Brantley County, Georgia. He is a Director of Okefenoke Rural EMC and was appointed Secretary and Treasurer in 2007.

H.B. Wiley, Jr. is the Member Director elected statewide. He became a member of the Board of Directors of Oglethorpe in March 2003 and his present term will expire in March 2009. He is also a member of the Audit Committee. Mr. Wiley previously served as a member of the Board of Directors from July 1994 until March 1997. Mr. Wiley has been an associate broker in real estate since 1994. Prior to that time, he owned and operated a dairy farm in Oconee County, Georgia from 1973 to 1994. During that time he served on the board of Atlanta Dairies Cooperative and Georgia Milk Producers Board. He has been a director of Walton EMC since June 1993, and served as its Chairman of the Board from June 2000 to June 2003. Mr. Wiley has a Bachelor of Science degree from the University of Georgia. Mr. Wiley served in the U.S. Army Engineers from 1968 to 1971, and is a Vietnam veteran.

Jeffrey W. Murphy is the Manager Director from the Northeast Region. He became a member of the

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Board of Directors of Oglethorpe in March 2004, and his present term will expire in March 2009. He is also a member of the Audit Committee. Mr. Murphy has been the President and CEO of Hart EMC since May 2002. He is also the Secretary of the Georgia Energy Cooperative.

Gary A. Miller is the Manager Director from the Northwest Region. Mr. Miller became a member of the Board of Directors of Oglethorpe in March 2004, and his present term will expire in March 2009. He is also a member of the Compensation Committee. Mr. Miller has been the President and CEO of GreyStone Power Corporation since January 1999. Mr. Miller is the Treasurer of the Development Authority of Douglas County. He is a past President of the Georgia Rural Electric Managers Association and is also a past Chairman of the Douglas County Chamber of Commerce. Mr. Miller is a member of the Board of Directors of CoBank where he also serves on the Audit Committee. Mr. Miller also currently serves on the Board of Trustees of WellStar Health System where he is on both the Audit and Finance Committees.

C. Hill Bentley is the Manager Director from the Central Region. He became a member of the Board of Directors of Oglethorpe in March 2004, and his present term will expire in March 2010. He is also a member of the Audit Committee. He is the CEO of Tri-County EMC. He is a member of the Boards of Directors of the Georgia Cooperative Council and the Central Georgia Technical College Foundation. Mr. Bentley is a member of the Bibb County Chamber of Commerce and the Georgia Chamber of Commerce, and is past President of the Jones County Chamber of Commerce. Mr. Bentley is a member, and a past President, of the Georgia Rural Electric Managers Association and is on the Business Advisory Council for Georgia College and State University.

Gary W. Wyatt is the Manager Director from the Southwest Region. He has served on the Board of Directors of Oglethorpe since March 2004. His present term will expire in March 2010. He is also a member of the Compensation Committee. He started his career in 1973 with Coosa Valley Electric Co-op in Talladega, Alabama where he held the position of Operations Manager. He assumed the position of President/CEO of Pataula EMC in 1986. Mr. Wyatt received an A.S. degree in management from Darton College. He is also a graduate of the National Rural Electric Cooperative Association Management Internship program at the University of Nebraska. He is on the Board of Directors of Georgia Electric Membership Corporation and is a past Vice Chairman of the Services Committee. Mr. Wyatt is the past President of the Georgia Managers Association, past Vice Chairman of the Albany Technical College Board of Directors and past President of the Randolph Cuthbert Chamber of Commerce.

Wm. Ronald Duffey is an Outside Director. He has served on the Board of Directors of Oglethorpe since March 1997. His present term will expire in March 2009. He is also the Chairman of the Audit Committee. Mr. Duffey is the Chairman of the Board of Directors of Peachtree National Bank in Peachtree City, Georgia, a wholly owned subsidiary of Synovus Financial Corp. Prior to his employment in 1985 with Peachtree National Bank, Mr. Duffey served as Executive Vice President and Member of the Board of Directors for First National Bank in Newnan, Georgia. He holds a Bachelor of Business Administration from Georgia State College with a concentration in finance and has completed banking courses at the School of Banking of the South, Louisiana State University, the American Bankers Association School of Bank Investments, and The Stonier Graduate School of Banking, Rutgers University. Mr. Duffey is a Director of Piedmont-Fayette Hospital, Piedmont-Newnan Hospital and The Georgia Economic Development Corp. Mr. Duffey is also a member of the Board of Directors of the Georgia Chamber of Commerce and of the Audit Committee of Piedmont Healthcare.

John S. Ranson is an Outside Director. He has served on the Board of Directors of Oglethorpe since March 1997. His present term will expire on March 31, 2008. He is also a member of the Compensation Committee. He has been the President of Ranson Municipal Consultants, L.L.C., a financial advisor in Wichita, Kansas, since 1994. From 1990 to 1994, Mr. Ranson was Chairman of Ranson Capital Corp., an investment banking firm. Mr. Ranson has been in the investment banking business since 1953. His public finance clients have included the Kansas Turnpike Authority, the Kansas Municipal Energy Agency, the Kansas Municipal Gas Agency, and the Kansas City (Kansas) Board of Public Utilities. Mr. Ranson received his Bachelor of Science in Business Administration from the University of Kansas (Lawrence, Kansas) and attended the Navy Supply Corps School in Bayonne, New Jersey.

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Committees of the Board of Directors

    The Board of Directors of Oglethorpe has established an Audit Committee and a Compensation Committee. The Audit Committee and the Compensation Committee each operate pursuant to a committee charter and/or policy. Oglethorpe does not have a Nominating and Corporate Governance Committee; directors are nominated by representatives from each Member whose weighted nomination is based on the number of retail customers served by each Member, and after nomination, elected by a majority vote of the Members, voting on a one-Member, one-vote basis. During 2007, the Board of Directors held nine Board meetings and nine committee meetings.

    Audit Committee.    The Audit Committee is responsible for assisting the Board of Directors in its oversight of all material aspects of the Company's financial reporting functions. Its responsibilities include selecting Oglethorpe's independent accountants, reviewing the plans, scope and results of the audit engagement with Oglethorpe's independent accountants, reviewing the independence of Oglethorpe's independent accountants and reviewing the adequacy of our internal accounting controls. The members of the Audit Committee are currently Wm. Ronald Duffey, Jeffrey W. Murphy, Marshall S. Millwood, C. Hill Bentley and H. B. Wiley, Jr. Mr. Duffey is the Chairman of the Audit Committee. The Board of Directors has determined that Mr. Duffey qualifies as an independent audit committee financial expert.

    Compensation Committee.    The Compensation Committee is responsible for monitoring adherence with Oglethorpe's compensation programs and recommending changes to its compensation programs as needed. The members of the Compensation Committee are J. Sam L. Rabun, John S. Ranson, Gary A. Miller, Gary W. Wyatt, M. Anthony Ham and Larry N. Chadwick.

Code of Ethics

    Oglethorpe has adopted a Code of Ethics that applies to the Executive Officers and the Controller of Oglethorpe. Oglethorpe's Code of Ethics is attached as an exhibit to this Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

Director Compensation

    The following table sets forth the total compensation paid or earned by each of Oglethorpe's directors for the fiscal year ended December 31, 2007.

Name		Total Fees Earned or Paid in Cash
Member Directors
Benny W. Denham, Chairman	$	13,810
J. Sam L. Rabun		19,000
Marshall S. Millwood		12,250
Larry N. Chadwick		11,750
M. Anthony Ham		9,450
H.B. Wiley, Jr.		12,550
Gary A. Miller		10,050
Jeffrey W. Murphy		10,850
C. Hill Bentley		10,850
Gary W. Wyatt		10,050
Robert E. Rentfrow (1)		10,850
Outside Directors
Wm. Ronald Duffey		31,250
John S. Ranson		19,750

(1)

Mr. Rentfrow ceased serving as an Oglethorpe Director on February 4, 2008. As Mr. Rentfrow was a Director of Oglethorpe throughout the fiscal year ended December 31, 2007, his compensation is included in this table.

    During 2006, Oglethorpe paid its Outside Directors a fee of $5,500 per Board meeting for four meetings a year and a fee of $1,000 per Board meeting for the remaining other Board meetings held during the year. Outside Directors were also paid $1,000 per day for attending committee meetings, annual meetings of the Members or other official business of Oglethorpe. Member Directors were paid a fee of $1,200 per Board meeting and $800 per day for attending committee meetings, other meetings except annual meetings of the Members, or other official business of Oglethorpe approved by the Chairman of the Board. Member Directors are paid $600 per day for attending the Annual Meeting of Members and Member Advisory Board meetings. In addition, Oglethorpe reimburses all Directors for out-of-pocket expenses incurred in attending a meeting. All Directors are paid $100 per day when participating in meetings by conference call. The Chairman of the Board is paid an additional 20 percent of his Director's fee per Board meeting for time involved in preparing for the meetings. The Chairman of the Audit Committee is paid an additional $400 per Audit Committee meeting for the time involved in fulfilling that role. Neither Oglethorpe's Outside Directors nor Member Directors receive any perquisites or other personal benefits.

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Compensation Discussion and Analysis

Overview of the Compensation Program

    The Compensation Committee of the Board has responsibility for establishing, implementing and monitoring adherence with Oglethorpe's compensation programs.

    Compensation Philosophy and Objectives.    The compensation and benefits program of Oglethorpe is designed to establish and maintain competitive total compensation programs that will attract, motivate and retain the qualified and skilled work force necessary for the continued success of Oglethorpe. To help align compensation paid to executive officers with the achievement of corporate goals, Oglethorpe has designed a significant portion of its cash compensation program as a pay for performance based system that rewards Executive Officers based on Oglethorpe's success in achieving the corporate goals discussed below. To remain competitive, each component of total compensation is validated relative to market values on an annual basis through the assessment of market data and benchmarking of compensation.

    Components of Total Compensation.    The Compensation Committee determined that compensation packages for the fiscal year ended December 31, 2007 for Oglethorpe's Executive Officers should be comprised of the following three primary components:

•

Annual base salary

•

Performance pay, which is a cash award given annually based on the achievement of corporate goals

•

Benefits, which consist primarily of health and welfare benefits and retirement benefits

    Base Salary.    Base salary is designed to attract and retain executives who can assist Oglethorpe in meeting its corporate goals. Oglethorpe believes that Executive Officer base salaries should be compared to the median of the range of salaries for executives in similar positions and with similar responsibilities at comparable companies. Base salary is established, in part, by surveying the external market. The Compensation Committee and Oglethorpe's President and Chief Executive Officer also factor in corporate performance and changes in individuals' roles and responsibilities when making decisions regarding Executive Officers' base salaries.

    Each of Oglethorpe's Executive Officers has an employment agreement that provides for a minimum annual base salary and performance pay. See the narrative disclosure following the "Summary Compensation Table" for additional information on the terms of the employment agreements.

    Performance Pay.    Performance pay is designed to reward Executive Officers based on Oglethorpe's success in achieving the corporate goals discussed below. Each Executive Officer has the potential to earn 20 percent of their base pay in performance pay. Each Executive Officer's performance pay award for 2007 was based 100 percent on the achievement of corporate goals, as determined by the Board of Directors upon the Compensation Committee's recommendation.

    Benefits.    The Benefits Program is designed to allow Executive Officers to choose the benefit options that best meet their needs. The President and Chief Executive Officer recommends changes to the benefits program or level of benefits that all Executive Officers, including the President and Chief Executive Officer, receive to the Compensation Committee. The Compensation Committee then reviews and recommends changes to the Board of Directors for its approval. To meet the health and welfare needs of its Executive Officers at a reasonable cost, Oglethorpe pays for 80-85 percent of an Executive Officer's health and welfare benefits. The President and Chief Executive Officer decides the exact cost sharing percentage to be borne by Oglethorpe.

    Oglethorpe also provides retirement benefits that allow Executive Officers the opportunity to develop an investment strategy that best meets their retirement needs. Oglethorpe will contribute up to $0.75 of every dollar an Executive Officer contributes to his or her retirement plan, up to 6 percent of an Executive Officer's pay per period, and will contribute an additional amount equal to 8 percent of an Executive Officer's pay per period. See "Nonqualified Deferred Compensation" for additional information regarding Oglethorpe's contributions to its Executive Officers' retirement plans.

    Perquisites.    Oglethorpe provides its Executive Officers with perquisites that Oglethorpe and the Compensation Committee believe are reasonable and consistent with its overall compensation program. The most significant perquisite provided to Oglethorpe's Executive Officers is a monthly car allowance, the

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amount of which is based upon the Executive Officer's position. The President and Chief Executive Officer approves the Executive Officers eligible for car allowances and reports this information to the Compensation Committee. The car allowance for the President and Chief Executive Officer is included in his employment agreement. The Compensation Committee periodically reviews the levels of perquisites provided to Executive Officers.

Establishing Compensation Levels

    Role of the Compensation Committee.    The Compensation Committee reviews changes to Oglethorpe's compensation program for its officers, directors and employees and recommends such changes to the Board of Directors for approval. Specifically, the Compensation Committee approves Oglethorpe's performance pay program, including the corporate goals related to such program. The Compensation Committee receives a comprehensive report on an annual basis regarding all facets of Oglethorpe's compensation program.

    The Compensation Committee operates pursuant to a Statement of Functions that sets forth the Committee's objectives and responsibilities. The Compensation Committee's objective is to review and recommend to the Board of Directors for approval any changes to various compensation related matters, as well as any significant changes in benefits cost or level of benefits, for the members of the Board of Directors, the Executive Officers, and employees of Oglethorpe. The Compensation Committee annually reviews the Statement of Functions and makes any necessary revisions to ensure its responsibilities are accurately stated.

    Role of Management.    The key member of management involved in the compensation process is the President and Chief Executive Officer. The President and Chief Executive Officer, together with the other Executive Officers, identifies corporate performance objectives that are used to determine performance pay amounts. The President and Chief Executive Officer and the Vice President, Human Resources present these goals to the Compensation Committee. The Compensation Committee then reviews and approves the goals and presents them to the Board of Directors for review and approval. The President and Chief Executive Officer approves the compensation of Oglethorpe's Executive Officers, other than the President and Chief Executive Officer, and in certain circumstances provides an upward adjustment to the Executive Officers' base salary. The President and Chief Executive Officer reports the Executive Officers' salaries to the Compensation Committee annually. The President and Chief Executive Officer's compensation is approved by the Board of Directors upon recommendation of the Compensation Committee.

    Role of the Compensation Consultant.    Oglethorpe engages a compensation consultant to assist it in reviewing its compensation program on a periodic basis. During 2006, Oglethorpe engaged Hewitt Associates, an outside global human resources consulting firm, to conduct a review of its compensation program. Hewitt Associates provided Oglethorpe with relevant market data that was used to analyze Oglethorpe's compensation program in light of the compensation programs of its peers and also to ensure that Oglethorpe's compensation program aligned with its stated compensation philosophy and objectives. Oglethorpe did not engage a compensation consultant during 2007.

Assessment of Market Data and Benchmarking of Compensation

    To remain competitive, Oglethorpe annually validates each component of total compensation paid to the Executive Officers relative to market values for compensation paid to similarly situated executives at companies Oglethorpe considers to be its peers. Oglethorpe refers to this practice as benchmarking and does not consider it the determinative factor in setting Executive Officers' compensation. Rather, Oglethorpe intends for benchmarking to supplement its other internal analyses regarding individual's performance in prior years and achievement of corporate goals that Oglethorpe considers when determining the performance pay component of Executive Officers' compensation.

    Oglethorpe's management establishes its peer group of companies by reviewing surveys of market data that focus on the utility industry. Management annually reviews the peer group's composition to ensure the companies included are relevant for comparative purposes.

    For 2007, Oglethorpe's peer group was composed of the companies included in the utilities industry sector reported in the U.S. Mercer Benchmark Survey, the 2007 Towers Perrin Executive Energy Survey, the companies included in the Utilities & Energy industry sector of the Watson Wyatt Top Management Report

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and the 2006 NRECA G&T Compensation Survey. Although there is a large variance in the size of the companies included in these surveys, Oglethorpe believes they serve as appropriate comparisons to it because they are in the utility industry. Therefore, these companies likely have operations similar to Oglethorpe and executives who have responsibilities and perform roles similar to its executives. In addition, these are the companies with whom Oglethorpe primarily competes for executive talent.

    The Mercer Benchmark Executive Survey includes 2,501 participants from a broad range of industry sectors with annual revenues ranging from $238 million to $21 billion annually. Oglethorpe focuses its comparison on Utilities sector participants with annual revenues ranging from $1 billion to $3 billion annually. Oglethorpe focused its comparison on these companies because they are most similar to Oglethorpe in terms of industry sector and revenues.

    The Towers Perrin Executive Energy Survey includes 91 participant companies with revenues ranging from less than $1 billion to greater than $6 billion annually. Oglethorpe typically focuses on the 29 participant companies that have revenues ranging from $1 billion to $3 billion when reviewing executive level compensation. Oglethorpe chooses to focus on these companies because their revenues are most similar to those of Oglethorpe.

    The Watson Wyatt Top Management Report includes 1,375 participants from a variety of industries. Oglethorpe focuses on the participant companies from the Utilities and Energy Sectors.

    The 2006 NRECA G&T Compensation Survey includes 50 companies, including Oglethorpe, all of whom are members of the National Rural Electric Cooperative Association. Although Oglethorpe believes compensation paid to executives at other electric cooperatives is a relevant comparison tool, Oglethorpe does not focus exclusively on these companies when benchmarking compensation because it is larger than most of the other companies included in this survey.

Assessment of Severance Arrangements

    Each of Oglethorpe's Executive Officers is entitled to certain severance payments and benefits in the event they are terminated not for cause or they resign for good reason. Oglethorpe negotiated each employment agreement with the Executive Officers on an arms-length basis, and the Compensation Committee determined that the terms of each agreement are reasonable and necessary to ensure that Oglethorpe's Executive Officers' goals are aligned with those of Oglethorpe and that each performs his or her respective role while acting solely in the best interests of Oglethorpe. See "Severance Arrangements" below for a discussion of the terms of each of the President and Chief Executive Officer's and other Executive Officers' agreements.

    The Compensation Committee last reviewed the President and Chief Executive Officer's employment agreement in November 2007. In determining that the President and Chief Executive Officer's employment agreement was appropriate and necessary, the Compensation Committee considered Mr. Smith's role and responsibility within Oglethorpe in relation to the total amount of severance pay he would receive upon the occurrence of a severance event. The Committee also considered whether the amount Mr. Smith would receive upon severance was appropriate given his total annual compensation.

    Upon review, the Compensation Committee determined that a maximum amount of severance compensation equal to a maximum of two year's compensation, plus benefits as described below, was an appropriate amount of severance compensation for Mr. Smith. The Compensation Committee believes that entering into a severance agreement with Oglethorpe's President and Chief Executive Officer is beneficial because it gives Oglethorpe a measure of stability in this position while affording it the flexibility to change management with minimal disruption, should Oglethorpe's Board of Directors ever determine such a change to be necessary and in the best interests of Oglethorpe. The Compensation Committee considered an amount equal to up to two years of compensation and benefits to be an appropriate amount to address competitive concerns and offset any potential risk Mr. Smith faces in his role as Oglethorpe's President and Chief Executive Officer. Furthermore, it should be noted that Oglethorpe does not compensate its President and Chief Executive Officer using options or other forms of equity compensation that typically lead executives to accumulate large amounts of wealth during employment.

    The Compensation Committee also reviewed the terms of each of the other Executive Officers' agreements. In its review, the Compensation Committee

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considered the total amount of compensation each Executive Officer would receive upon the occurrence of a severance event. The Compensation Committee determined that it was also appropriate for Oglethorpe's other Executive Officers to receive severance compensation equal to one year's compensation, plus benefits as described below, because such agreements provide a measure of stability for both Oglethorpe and its other Executive Officers. In addition, like its President and Chief Executive Officer, Oglethorpe's other Executive Officers are not compensated using options or other forms of equity compensation that lead to significant wealth accumulation. Therefore, the Compensation Committee believed such severance compensation is necessary to address competitive concerns and offset any potential risk Oglethorpe's Executive Officers face in the course of their employment.

    The Compensation Committee will continue to review these agreements annually.

Assessment of Corporate and Executive Officer Performance

    Each year Oglethorpe drafts a comprehensive set of corporate goals which are approved by the Board of Directors. For 2007, Oglethorpe's corporate goals primarily involved the following: (i) the operation of Oglethorpe's plants by facility type, (ii) Oglethorpe's financial performance for the year, including cost savings and risk reduction programs, (iii) environmental compliance, (iv) quality of performance and (v) safety.

    Oglethorpe chose to tie performance compensation to these corporate goals because they most appropriately measure what it aims to accomplish. For Oglethorpe to be successful it must perform sound asset management by acquiring and managing the power supply resources necessary to serve its customers effectively. To do this, Oglethorpe must operate efficiently, safely, and in a financially sound manner that meets the expectations of its Members, as represented by its Board of Directors. Oglethorpe reviews these corporate goals annually and makes adjustments as needed to ensure that it is consistently stretching its goal expectations.

    Performance pay paid to Oglethorpe's Executive Officers is determined based on Oglethorpe's success in achieving each of the goals identified above. Oglethorpe's Board of Directors annually approves a weighted system for determining performance pay whereby it assigns a percentage to each of the goals identified above. At the end of each fiscal year, Oglethorpe determines goal achievement for each of the five categories. Based on the achievement for each category, Oglethorpe assigns a percentage, up to the maximum percentage allowed for each category, to determine the amount of performance pay available to its Executive Officers. For each Executive Officer, Oglethorpe then multiplies 20 percent of his or her base salary by the goal achievement percentage amount. For example, if Oglethorpe had a 90 percent corporate goal achievement rate in a given year, each Executive Officer's performance pay would equal (base salary × 20%) × (90%).Set forth below is a chart summarizing Oglethorpe's corporate goal weighting system for 2007 as approved by its Board of Directors in February 2007:

Goal	Weighted Percentage
Operations	35	%
Financial	35	%
Quality	15	%
Environmental Compliance	10	%
Safety	5	%

    Oglethorpe measures goal achievement in each of the above categories as follows: Oglethorpe bases its operations achievements on how well each of its operating plants respond to system requirements. In reviewing Oglethorpe's success in meeting its financial goals, Oglethorpe considers what cost savings and cost reduction programs are implemented in a given year that will result in cost savings either in the current year or on a long-term basis. Oglethorpe also considers whether any programs were implemented that may not have resulted in cost savings in the current year, but nonetheless increased the value of its assets or reduced potential risk. Oglethorpe measures its quality goal performance based on the performance appraisal of the Members, as represented by the Board of Directors. Environmental compliance is measured by considering whether Oglethorpe received notices of violation or letters of noncompliance, or had any spills at any of its facilities. Safety performance is measured by reviewing Oglethorpe's standards and the safety of its work environment against those of other electric utilities.

Analysis of 2007 Compensation paid to Executive Officers

    As explained above, in identifying prevailing market compensation for similarly situated companies, Oglethorpe considers market data as well as

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achievement of corporate and individual goals. In determining individual compensation for Oglethorpe's Executive Officers, the Compensation Committee considers the total compensation awarded to each individual, and a percentage of each Executive Officer's annual compensation is based on corporate performance. This approach allows Oglethorpe to maintain the flexibility necessary to differentiate pay in recognition of corporate performance.

    Executive Officers' performance pay is based solely on the achievement of corporate goals. The Compensation Committee believes it is appropriate to consider only corporate goal achievement when determining Executive Officers' performance pay because Oglethorpe's corporate philosophy focuses on teamwork, and Oglethorpe believes that better results evolve from mutual work towards common goals. Furthermore, the Compensation Committee believes that Oglethorpe's achievement of the corporate goals identified above will correspond to high company performance, and Oglethorpe's Executive Officers are responsible for directing the work and making the strategic decisions necessary to successfully meet these goals.

    In 2007, Oglethorpe's corporate goal achievement was 81.5 percent. Goal achievement rate by category based on the weighted system identified above was as follows:

Goal	Weighted Percentage
Operations	19.2	%
Financial	35.0	%
Quality	12.3	%
Environmental Compliance	10.0	%
Safety	5.0	%
Total	81.5	%

    Oglethorpe achieved 81.5 percent of its corporate goals for 2007 primarily because it met all of its financial, environmental compliance, and safety goals. With respect to operations, Oglethorpe did not meet all of its goals primarily because two of the operating plants it used to measure its operations goal achievement had successful plant start rates during the peak season that fell below the goals set for those plants. As a result of achieving 81.5 percent of Oglethorpe's corporate goals for 2007, each of its Executive Officers received performance pay in an amount equal to 81.5 percent of 20 percent of his or her base salary. Set forth below is a table showing 2007 performance pay figures for each of Oglethorpe's Executive Officers:

Executive Officer		Performance Pay *
Smith	$	77,425
Price	$	45,640
Higgins	$	44,825
Ussery	$	31,622
Robbins	$	28,036
Reusch	$	25,428

*

Performance pay was calculated based on base salaries as of December 31, 2007. Actual compensation earned in 2007 is reported in the Summary Compensation Table below.

Compensation Committee Interlocks and Insider Participation

    J. Sam L. Rabun, John S. Ranson, Gary A. Miller, Gary W. Wyatt, M. Anthony Ham, C. Hill Bentley and Larry N. Chadwick served as members of the Oglethorpe Power Corporation Compensation Committee in 2007. Mr. Bentley served on the Compensation Committee through March 31, 2007. Mr. Wyatt began serving on the Compensation Committee on March 31, 2007. J. Sam L. Rabun served as the Vice Chairman of the Board in 2007.

    Gary A. Miller is a Director of Oglethorpe and the President and Chief Executive Officer of GreyStone Power Corporation. GreyStone Power Corporation is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. GreyStone Power Corporation's payments of $83.9 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately 7.3 percent of Oglethorpe's total revenues.

    C. Hill Bentley is a Director of Oglethorpe and the Chief Executive Officer of Tri-County EMC. Tri-County EMC is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. Tri-County EMC's payments of $13.4 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately 1.2 percent of Oglethorpe's total revenues.

    Gary W. Wyatt is a Director of Oglethorpe and the President and Chief Executive Officer of Pataula EMC. Pataula EMC is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. Pataula EMC's payments of $2.4 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for

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approximately less than 1 percent of Oglethorpe's total revenues.

Compensation Committee Report

    The Compensation Committee of Oglethorpe Power Corporation has reviewed and discussed the Compensation Discussion and Analysis required by Item 402(b) of Regulation S-K with management and, based on such review and discussions, the Compensation Committee recommended to the Board that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the fiscal year ended December 31, 2007 for filing with the SEC.

Respectfully Submitted,

The Compensation Committee

J. Sam L. Rabun
John S. Ranson
Gary A. Miller
Gary W. Wyatt
M. Anthony Ham
Larry N. Chadwick

Summary Compensation Table

    The following table sets forth the total compensation paid or earned by each of Oglethorpe's Executive Officers for the fiscal years ended December 31, 2007 and 2006.

Name and Principal Position	Year		Salary		Non-Equity Incentive Plan Compensation		All Other Compensation (1)		Total
Thomas A. Smith President and Chief Executive Officer	2007 2006	$	469,313 438,043	$	77,425 72,126	$	68,332 51,582	$	615,070 561,751
Michael W. Price Chief Operating Officer	2007 2006		275,853 253,481		45,640 44,059		57,261 35,925		378,754 333,465
Elizabeth B. Higgins Chief Financial Officer	2007 2006		270,314 245,304		44,825 42,637		44,722 35,112		359,861 323,053
William F. Ussery Senior Vice President, Member and External Relations	2007 2006		190,283 171,417		31,622 29,653		36,087 27,697		257,992 228,767
W. Clayton Robbins Senior Vice President, Chief Administrative Officer	2007 2006		170,667 154,487		28,036 26,273		64,126 73,550		262,829 254,310
Jami G. Reusch Vice President, Human Resources	2007 2006		154,766 147,643		25,428 23,805		32,081 27,341		212,275 198,789

(1)

Figures for 2007 consist of customary holiday gifts, matching contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch of $10,115, $10,125, $10,125, $8,563, $9,987, and $8,036, respectively; [contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch of $19,385, $18,000, $18,000, $17,595, $17,755, and $14,286, respectively;] contributions by Oglethorpe to a nonqualified deferred compensation plan on behalf of Mr. Smith, Mr. Price and Ms. Higgins of $25,514, $8,456, and $7,036, respectively; a transition payment of $25,000 for services rendered by Mr. Robbins as Chief Administrative Officer; a payment to Mr. Price for unused paid leave time accrued; a car allowance of $12,000, $9,000, $9,000, $9,000, $9,000, and $9,000 for Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch respectively; and insurance premiums paid on term life insurance on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch of $1,242, $810, $485, $854, $2,307, $683, respectively.

Figures for 2006 consist of matching contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch and of $9,895, $9,658, $9,707, $7,395, $9,900, and $8,382, respectively; contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch of $11,000, $11,000, $11,000, $10,428, $11,000, and $9,313, respectively; contributions by Oglethorpe to a nonqualified deferred compensation plan on behalf of Mr. Smith, Mr. Price, Ms. Higgins and Mr. Robbins of $17,445, $5,460, $4,929, and $1,610, respectively; a transition payment of $40,000 for services rendered by Mr. Robbins as Chief Administrative Officer; a car allowance of $12,000, $9,000, $9,000, $9,000, $9,000, and $9,000 for Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch respectively; and insurance premiums paid on term life insurance on behalf of Mr. Smith, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch of $1,242, $807, $475, $874, $2,040, $645, respectively.

    Oglethorpe entered into an employment agreement with Thomas A. Smith, Oglethorpe's President and Chief Executive Officer, effective March 15, 2002. Oglethorpe entered into a restated employment agreement with Mr. Smith effective January 1, 2007. The initial term of the 2007 agreement extends until December 31, 2009, and automatically renews for successive one-year periods unless either party provides written notice not to renew the agreement on or before November 30, 2007 (for the initial term) or twenty-five months before the expiration of any extended term. No such notice has been provided. Mr. Smith's minimum annual base salary under the 2007 agreement is $440,870, and is subject to review and possible upward adjustment by the Board of Directors. Mr. Smith is eligible for an annual bonus or other incentive compensation plans generally available to similarly situated employees, determined by Oglethorpe's Board

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of Directors in its sole discretion. Mr. Smith is also entitled to an automobile or an automobile allowance during the term of the 2007 agreement. Mr. Smith's employment agreement contains severance pay provisions. Details regarding the severance pay provisions of the agreement are provided under "Severance Arrangements".

    Effective January 1, 2007, Oglethorpe entered into employment agreements with Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch. Each agreement extends through December 31, 2008, and automatically renews for successive one-year periods unless either party provides written notice not to renew the agreement on or before November 30, 2007 (for the initial term) or thirteen months before the expiration of any extended term. No such notices have been provided. Minimum annual base salaries under the 2007 agreements are $255,116 for Mr. Price, $246,887 for Ms. Higgins, $171,700 for Mr. Ussery, $164,000 for Mr. Robbins, and $148,596 for Ms. Reusch. Salaries are subject to review and possible upward adjustment as determined by the President and the Chief Executive Officer. Each executive is also eligible for an annual bonus or other incentive compensation plans generally available to similarly situated employees, determined by Oglethorpe in its sole discretion. The employment agreements with Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins, and Ms. Reusch contain severance pay provisions. Details regarding the severance pay provisions of the agreements are provided under "Severance Arrangements".

Grants of Plan-Based Award Table

    The following table sets forth certain information with respect to the performance pay for the fiscal year ended December 31, 2007 awarded to the Executive Officers listed in the Summary Compensation Table.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards
Name	Grant Date		Threshold (1)		Target (2)
Thomas A. Smith President and Chief Executive Officer	N/A	$	23,655	$	95,000
Michael W. Price Chief Operating Officer	N/A		13,944		56,000
Elizabeth B. Higgins Chief Financial Officer	N/A		13,695		55,000
William F. Ussery Senior Vice President, Member and External Relations	N/A		9,661		38,800
W. Clayton Robbins Senior Vice President, Chief Administrative Officer	N/A		8,566		34,400
Jami G. Reusch Vice President, Human Resources	N/A		7,769		31,200

(1)

These figures represent the amount each Executive Officer would receive if the threshold goal achievement percentages were reached in each of the goal categories identified above. See "Compensation Discussion and Analysis – Assessment of Corporate and Executive Officer Performance – Performance Pay."

(2)

This amount represents 20 percent of the Executive Officer's base salary. See "Compensation Discussion and Analysis – Assessment of Corporate and Executive Officer Performance – Performance Pay" for additional information.

    For an explanation of the criteria and formula used to determine the awards listed above, please refer to the discussion entitled "Assessment of Corporate and Executive Officer Performance" included in the Compensation Discussion and Analysis.

Nonqualified Deferred Compensation

    Oglethorpe maintains a Fidelity Non-Qualified Deferred Compensation Program. The Nonqualified Deferred Compensation Program serves as a vehicle through which Oglethorpe can continue contributions to its Executive Officers via its Employer Retirement Contribution to its Executive Officers beyond the IRS salary limits on the retirement plan ($220,000 as indexed). The following table sets forth contributions by

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Oglethorpe for the fiscal year ended December 31, 2007 along with aggregate earnings for the same period.

Name		Registrant Contributions in Last FY (1)		Aggregate Earnings in Last FY (2)		Aggregate Balance at Last FYE
Thomas A. Smith President and Chief Executive Officer	$	25,514	$	3,454	$	47,576
Michael W. Price Chief Operating Officer		8,456		710		14,844
Elizabeth B. Higgins Chief Financial Officer		7,036		246		12,427
William F. Ussery Senior Vice President, Member and External Relations		–		–		–
W. Clayton Robbins Senior Vice President, Chief Administrative Officer		–		88		1,701
Jami G. Reusch Vice President, Human Resources		–		–		–

(1)

All registrant contribution amounts shown have been included in the "All Other Compensation" column of the Summary Compensation Table above.

(2)

A participant's account under the Fidelity Non-Qualified Deferred Compensation Program is invested in the investment options selected by the participant. The account is credited with gains or losses actually experienced by the investments.

Severance Arrangements

    Pursuant to the terms of his employment agreement, Mr. Smith will be entitled to a lump-sum severance payment upon the occurrence of any of the following events: (1) Oglethorpe terminates Mr. Smith's employment without cause; or (2) Mr. Smith resigns due to a demotion or material reduction of his position or responsibilities, reduction of his base salary, or a relocation of Mr. Smith's principal office by more than 50 miles. The severance payment will equal Mr. Smith's base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), and is payable within 30 days of termination, subject to the provisions of Internal Revenue Code Section 409A. In addition, Mr. Smith will be entitled to outplacement services provided by Oglethorpe and an amount equal to Mr. Smith's costs for medical and dental continuation coverage under COBRA, each for the longer of one year or the remaining term of the agreement. Severance is payable only if Mr. Smith signs a form releasing all claims against Oglethorpe within 45 days after his termination date. The maximum severance that would be payable to Mr. Smith in the circumstances described above is $1,157,221.

    Pursuant to the terms of their employment agreements, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins, and Ms. Reusch will each be entitled to a lump-sum severance payment if Oglethorpe terminates the executive without cause or if the executive resigns after a demotion or material reduction of his or her position or responsibilities, a reduction of his or her base salary, or a relocation of his or her principal office by more than 50 miles. The severance payment will equal the one year of the executive's base salary, payable six months after the executive's termination date. In addition, the executive will be entitled to six months of outplacement services provided by Oglethorpe and an amount equal to the executive's cost for medical and dental continuation coverage under COBRA for six months. Severance is payable only if the executive signs a form releasing all claims against Oglethorpe within 45 days after his or her termination date. The maximum severance that would be payable to Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch in the circumstances described above is $331,110, $331,110, $240,108, $200,672 and $179,693, respectively.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

    Not Applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Certain Relationships and Related Transactions

    During 2007, Robert E. Rentfrow was a Director of Oglethorpe and the President and Chief Executive Officer of Satilla Rural EMC. Satilla Rural EMC is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. Satilla Rural EMC's payment of $28.9 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately 2.5 percent of Oglethorpe's total revenue.

    Jeffrey W. Murphy is a Director of Oglethorpe and the President and Chief Executive Officer of Hart EMC. Hart EMC is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. Hart EMC's payments of $21.9 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately 1.9 percent of Oglethorpe's total revenues.

    Gary A. Miller is a Director of Oglethorpe and the President and Chief Executive Officer of GreyStone Power Corporation. GreyStone Power Corporation is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. GreyStone Power Corporation's payments of $83.9 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately 7.3 percent of Oglethorpe's total revenues.

    C. Hill Bentley is a Director of Oglethorpe and the Chief Executive Officer of Tri-County EMC. Tri-County EMC is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. Tri-County EMC's payments of $13.4 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately 1.2 percent of Oglethorpe's total revenues.

    Gary W. Wyatt is a Director of Oglethorpe and the President and Chief Executive Officer of Pataula EMC. Pataula EMC is a Member of Oglethorpe and has a Wholesale Power Contract with Oglethorpe. Pataula EMC's payments of $2.4 million to Oglethorpe in 2007 under the Wholesale Power Contract accounted for approximately less than 1 percent of Oglethorpe's total revenues and. Pataula EMC is owned by another Member of Oglethorpe, Cobb EMC.

    Herbert J. Short served as Oglethorpe's General Counsel during 2007. Mr. Short is a partner with Sutherland Asbill & Brennan LLP. Sutherland Asbill & Brennan LLP provides legal services to Oglethorpe on a regular basis.

    Oglethorpe has a Standards of Conduct/ Conflict of Interest policy (the "Policy") that sets forth guidelines that its employees and directors must follow in order to avoid conflicts of interest, or any appearance of conflicts of interest, between an individual's personal interests and the interests of Oglethorpe. Pursuant to the Policy, each employee and director must disclose any conflicts of interest, actions or relationships that might give rise to a conflict. The President and Chief Executive Officer is responsible for taking reasonable steps to ensure that the employees are complying with the Policy and the Audit Committee is responsible for taking reasonable steps to ensure that the directors are complying with the Policy. The Audit Committee is charged with monitoring compliance with the Policy and making recommendations to the Board of Directors regarding the Policy. Certain actions or relationships that might give rise to a conflict of interest are reviewed and approved by the Board of Directors.

Director Independence

    Because Oglethorpe is an electric cooperative, the members it serves own and manage Oglethorpe. Oglethorpe's Bylaws set forth specific requirements regarding the composition of its Board of Directors. Specifically, Oglethorpe has a thirteen member Board of Directors consisting of eleven directors elected from the Members (the "Member Directors") and two independent outside directors (the "Outside Directors"). Five Member Directors must be a general manager of an Oglethorpe Member located in each of the five geographical regions of the State of Georgia and an additional five Member Directors must be a director of an Oglethorpe Member located in each of the five geographical regions of the State of Georgia. The eleventh Member Director must be a director of an Oglethorpe Member. An Oglethorpe Member must not have both its general manager and one of its directors serve as a director of Oglethorpe at the same time.

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    In addition to meeting the requirements set forth in its Bylaws, all directors, with the exception of Gary A. Miller, satisfy the definition of director independence as prescribed by the NASDAQ Stock Market and otherwise meet the requirements set forth in Oglethorpe's Bylaws. Gary A. Miller does not qualify as an independent director because he is the President and Chief Executive Officer of GreyStone Power Corporation, which accounted for approximately 7.5 percent of Oglethorpe's revenues for the fiscal year ended December 31, 2007. Although Oglethorpe does not have any securities listed on the NASDAQ Stock Market, Oglethorpe has used the NASDAQ Stock Market's independence criteria in making this determination in accordance with applicable SEC rules.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

    For 2007 and 2006, fees for services provided by Oglethorpe's principal accountants, PricewaterhouseCoopers LLP were as follows:

		(dollars in thousands)
		2007		2006
Audit Fees (1)	$	341	$	358
Tax Fees (2)		25		27
Audit-Related Fees (3)		–		4
All Other Fees		–		–
Total	$	366	$	389

(1)

Audit of annual financial statements and review of financial statements included in SEC filings and services rendered in connection with financings.

(2)

Professional tax services including tax consultation and tax return preparation.

(3)

Audit related services rendered in connection with future Section 404 compliance requirements.

    In considering the nature of the services provided by the independent auditor, the Audit Committee determined that such services are compatible with the provision of independent audit services. The Audit Committee discussed these services with management to determine that they are permitted under the rules and regulations concerning auditor independence promulgated by the Securities and Exchange Commission to implement the Sarbanes-Oxley Act of 2002, as well as the American Institute of Certified Public Accountants.

Pre-Approval Policy

    The services performed by Pricewaterhouse Coopers LLP in 2007 were pre-approved in accordance with the pre-approval policy and procedures adopted by the Audit Committee. The policy requires that requests for all services must be submitted to the Audit Committee for specific pre-approval and cannot commence until such approval has been granted. Normally, pre-approval is provided at regularly scheduled meetings.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)  List of Documents Filed as a Part of This Report.

		Page
(1)	Financial Statements (Included under "Financial Statements and Supplementary Data")
	Consolidated Statements of Revenues and Expenses, For the Years Ended December 31, 2007, 2006 and 2005	51
	Consolidated Balance Sheets, As of December 31, 2007 and 2006	52
	Consolidated Statements of Capitalization, As of December 31, 2007 and 2006	54
	Consolidated Statements of Cash Flows, For the Years Ended December 31, 2007, 2006 and 2005	55
	Consolidated Statements of Patronage Capital and Membership Fees And Accumulated Other Comprehensive Deficit For the Years Ended December 31, 2007, 2006 and 2005	56
	Notes to Consolidated Financial Statements	57
	Report of Independent Registered Public Accounting Firm	77
(2)	Financial Statement Schedules
	None applicable.
(3)	Exhibits

    Exhibits marked with an asterisk (*) are hereby incorporated by reference to exhibits previously filed by the Registrant as indicated in parentheses following the description of the exhibit.

Number		Description
*2.1	–	Second Amended and Restated Restructuring Agreement, dated February 24, 1997, by and among Oglethorpe, Georgia Transmission Corporation (An Electric Membership Corporation) and Georgia System Operations Corporation. (Filed as Exhibit 2.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*2.2	–	Member Agreement, dated August 1, 1996, by and among Oglethorpe, Georgia Transmission Corporation (An Electric Membership Corporation), Georgia System Operations Corporation and the Members of Oglethorpe. (Filed as Exhibit 2.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*3.1(a)	–	Restated Articles of Incorporation of Oglethorpe, dated as of July 26, 1988. (Filed as Exhibit 3.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.)
*3.1(b)	–	Amendment to Articles of Incorporation of Oglethorpe, dated as of March 11, 1997. (Filed as Exhibit 3(i)(b) to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*3.2	–	Bylaws of Oglethorpe, as amended and restated, as of March 21, 2005. (Filed as Exhibit 3.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 2004, File No. 33-7591.)
*4.1	–	Form of Serial Facility Bond Due June 30, 2011 (included in Collateral Trust Indenture filed as Exhibit 4.2.)
*4.2	–	Collateral Trust Indenture, dated as of December 1, 1997, between OPC Scherer 1997 Funding Corporation A, Oglethorpe and SunTrust Bank, Atlanta, as Trustee. (Filed as Exhibit 4.2 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.3	–	Nonrecourse Promissory Lessor Note No. 2, with a Schedule identifying three other substantially identical Nonrecourse Promissory Lessor Notes and any material differences. (Filed as Exhibit 4.3 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)

95

*4.4	–	Amended and Restated Indenture of Trust, Deed to Secure Debt and Security Agreement No. 2, dated December 1, 1997, between Wilmington Trust Company and NationsBank, N.A. collectively as Owner Trustee, under Trust Agreement No. 2, dated December 30, 1985, with DFO Partnership, as assignee of Ford Motor Credit Company, and The Bank of New York Trust Company of Florida, N.A. as Indenture Trustee, with a Schedule identifying three other substantially identical Amended and Restated Indentures of Trust, Deeds to Secure Debt and Security Agreements and any material differences. (Filed as Exhibit 4.4 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.5(a)	–	Lease Agreement No. 2 dated December 30, 1985, between Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessor, and Oglethorpe, Lessee, with a Schedule identifying three other substantially identical Lease Agreements. (Filed as Exhibit 4.5(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*4.5(b)	–	First Supplement to Lease Agreement No. 2 (included as Exhibit B to the Supplemental Participation Agreement No. 2 listed as 10.1.1(b)).
*4.5(c)	–	First Supplement to Lease Agreement No. 1, dated as of June 30, 1987, between The Citizens and Southern National Bank as Owner Trustee under Trust Agreement No. 1 with IBM Credit Financing Corporation, as Lessor, and Oglethorpe, as Lessee. (Filed as Exhibit 4.5(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)
*4.5(d)	–	Second Supplement to Lease Agreement No. 2, dated as of December 17, 1997, between NationsBank, N.A., acting through its agent, The Bank of New York, as an Owner Trustee under the Trust Agreement No. 2, dated December 30, 1985, among DFO Partnership, as assignee of Ford Motor Credit Company, as the Owner Participant, and the Original Trustee, as Lessor, and Oglethorpe, as Lessee, with a Schedule identifying three other substantially identical Second Supplements to Lease Agreements and any material differences. (Filed as Exhibit 4.5(d) to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*4.6	–	Third Amended and Restated Loan Contract, dated as of July 25, 2007, between Oglethorpe and the United States of America, together with two notes executed and delivered pursuant thereto. (Filed as Exhibit 4.6 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2007, File No. 33-7591.)
*4.7.1(a)	–	Indenture, dated as of March 1, 1997, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*4.7.1(b)	–	First Supplemental Indenture, dated as of October 1, 1997, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1997B (Burke) Note. (Filed as Exhibit 4.8.1(b) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1997, File No. 33-7591.)
*4.7.1(c)	–	Second Supplemental Indenture, dated as of January 1, 1998, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 1997C (Burke) Note. (Filed as Exhibit 4.7.1(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1997, File No. 33-7591.)
*4.7.1(d)	–	Third Supplemental Indenture, dated as of January 1, 1998, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 1997A (Monroe) Note. (Filed as Exhibit 4.7.1(d) to the Registrant's Form 10-K for the fiscal year December 31, 1997, File No. 33-7591.)
*4.7.1(e)	–	Fourth Supplemental Indenture, dated as of March 1, 1998, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1998A (Burke) and 1998B (Burke) Notes. (Filed as Exhibit 4.7.1(e) to the Registrant's Form 10-K for the fiscal year ended December 31, 1998, File No. 33-7591.)
*4.7.1(f)	–	Fifth Supplemental Indenture, dated as of April 1, 1998, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1998 CFC Note. (Filed as Exhibit 4.7.1(f) to the Registrant's Form 10-K for the fiscal year ended December 31, 1998, File No. 33-7591.)

96

*4.7.1(g)	–	Sixth Supplemental Indenture, dated as of January 1, 1999, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1998C (Burke) Note. (Filed as Exhibit 4.7.1(g) to the Registrant's Form 10-K for the fiscal year ended December 31, 1998, File No. 33-7591.)
*4.7.1(h)	–	Seventh Supplemental Indenture, dated as of January 1, 1999, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1998A (Monroe) Note. (Filed as Exhibit 4.7.1(h) to the Registrant's Form 10-K for the fiscal year ended December 31, 1998, File No. 33-7591.)
*4.7.1(i)	–	Eighth Supplemental Indenture, dated as of November 1, 1999, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1999B (Burke) Note. (Filed as Exhibit 4.7.1(i) to the Registrant's Form 10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)
*4.7.1(j)	–	Ninth Supplemental Indenture, dated as of November 1, 1999, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1999B (Monroe) Note. (Filed as Exhibit 4.7.1(j) to the Registrant's Form 10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)
*4.7.1(k)	–	Tenth Supplemental Indenture, dated as of December 1, 1999, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee, relating to the Series 1999 Lease Notes. (Filed as Exhibit 4.7.1(k) to the Registrant's Form 10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)
*4.7.1(l)	–	Eleventh Supplemental Indenture, dated as of January 1, 2000, made by Oglethorpe to SunTrust Bank as trustee, relating to the Series 1999A (Burke) Note. (Filed as Exhibit 4.7.1(l) to the Registrant's Form 10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)
*4.7.1(m)	–	Twelfth Supplemental Indenture, dated as of January 1, 2000, made by Oglethorpe to SunTrust Bank as trustee, relating to the Series 1999A (Monroe) Note. (Filed as Exhibit 4.7.1(m) to the Registrant's Form 10-K for the fiscal year ended December 31, 1999, File No. 33-7591.)
*4.7.1(n)	–	Thirteenth Supplemental Indenture, dated as of January 1, 2001, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2000 (Burke) Note. (Filed as Exhibit 4.7.1(n) to the Registrant's Form 10-K for the fiscal year ended December 31, 2000, File No. 33-7591.)
*4.7.1(o)	–	Fourteenth Supplemental Indenture, dated as of January 1, 2001, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2000 (Monroe) Note. (Filed as Exhibit 4.7.1(o) to the Registrant's Form 10-K for the fiscal year ended December 31, 2000, File No. 33-7591.)
*4.7.1(p)	–	Fifteenth Supplemental Indenture, dated as of January 1, 2002, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2001 (Burke) Note. (Filed as Exhibit 4.7.1(p) to the Registrant's Form 10-K for the fiscal year ended December 31, 2001, File No. 33-7591.)
*4.7.1(q)	–	Sixteenth Supplemental Indenture, dated as of January 1, 2002, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2001 (Monroe) Note. (Filed as Exhibit 4.7.1(q) to the Registrant's Form 10-K for the fiscal year ended December 31, 2001, File No. 33-7591.)
*4.7.1(r)	–	Seventeenth Supplemental Indenture, dated as of October 1, 2002, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2002A (Burke) Note. (Filed as Exhibit 4.7.1(r) to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, File No. 33-7591.)

97

*4.7.1(s)	–	Eighteenth Supplemental Indenture, dated as of October 1, 2002, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2002B (Burke) Note. (Filed as Exhibit 4.7.1(s) to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, File No. 33-7591.)
*4.7.1(t)	–	Nineteenth Supplemental Indenture, dated as of January 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2002C (Burke) Note. (Filed as Exhibit 4.7.1(t) to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, File No. 33-7591.)
*4.7.1(u)	–	Twentieth Supplemental Indenture, dated as of January 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2002 (Monroe) Note. (Filed as Exhibit 4.7.1(u) to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, File No. 33-7591.)
*4.7.1(v)	–	Twenty-First Supplemental Indenture, dated as of January 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2002 (Appling) Note. (Filed as Exhibit 4.7.1(v) to the Registrant's Form 10-K for the fiscal year ended December 31, 2002, File No. 33-7591.)
*4.7.1(w)	–	Twenty-Second Supplemental Indenture, dated as of March 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003 (FFB M-8) Note and Series 2003 (RUS M-8) Reimbursement Note. (Filed as Exhibit 4.7.1(w) to the Registrant's Form 10-Q for the quarterly period ended September 30, 2003, File No. 33-7591.)
*4.7.1(x)	–	Twenty-Third Supplemental Indenture, dated as of March 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003 (FFB N-8) Note and Series 2003 (RUS N-8) Reimbursement Note. (Filed as Exhibit 4.7.1(x) to the Registrant's Form 10-Q for the quarterly period ended September 30, 2003, File No. 33-7591.)
*4.7.1(y)	–	Twenty-Fourth Supplemental Indenture, dated as of December 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003A (Appling) Note. (Filed as Exhibit 4.7.1(y) to the Registrant's Form 10-K for the fiscal year ended December 31, 2003, File No. 33-7591.)
*4.7.1(z)	–	Twenty-Fifth Supplemental Indenture, dated as of December 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003A (Burke) Note. (Filed as Exhibit 4.7.1(z) to the Registrant's Form 10-K for the fiscal year ended December 31, 2003, File No. 33-7591.)
*4.7.1(aa)	–	Twenty-Sixth Supplemental Indenture, dated as of December 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003B (Burke) Note. (Filed as Exhibit 4.7.1(aa) to the Registrant's Form 10-K for the fiscal year ended December 31, 2003, File No. 33-7591.)
*4.7.1(bb)	–	Twenty-Seventh Supplemental Indenture, dated as of December 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003A (Heard) Note. (Filed as Exhibit 4.7.1(bb) to the Registrant's Form 10-K for the fiscal year ended December 31, 2003, File No. 33-7591.)
*4.7.1(cc)	–	Twenty-Eighth Supplemental Indenture, dated as of December 1, 2003, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2003A (Monroe) Note. (Filed as Exhibit 4.7.1(cc) to the Registrant's Form 10-K for the fiscal year ended December 31, 2003, File No. 33-7591.)
*4.7.1(dd)	–	Twenty-Ninth Supplemental Indenture, dated as of December 1, 2004, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2004 (Burke) Note. (Filed as Exhibit 4.7.1(dd) to the Registrant's Form 10-K for the fiscal year ended December 31, 2004, File No. 33-7591.)

98

*4.7.1(ee)	–	Thirtieth Supplemental Indenture, dated as of December 1, 2004, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2004 (Monroe) Note. (Filed as Exhibit 4.7.1(ee) to the Registrant's Form 10-K for the fiscal year ended December 31, 2004, File No. 33-7591.)
*4.7.1(ff)	–	Thirty-First Supplemental Indenture, dated as of November 1, 2005, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2005 (Burke) Note. (Filed as Exhibit 4.7.1(ff) to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, File No. 33-7591.)
*4.7.1(gg)	–	Thirty-Second Supplemental Indenture, dated as of November 1, 2005, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2005 (Monroe) Note. (Filed as Exhibit 4.7.1(gg) to the Registrant's Form 10-K for the fiscal year ended December 31, 2005, File No. 33-7591.)
*4.7.1(hh)	–	Thirty-Third Supplemental Indenture, dated as of May 1, 2006, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Series 2006 (FFB P-8) Note and Series 2006 (RUS P-8) Reimbursement Note. (Filed as Exhibit 4.7.1(hh) to the Registrant's Form 10-Q for the quarterly period ended June 30, 2006, File No. 33-7591.)
*4.7.1(ii)	–	Thirty-Fourth Supplemental Indenture, dated as of September 22, 2006, made by Oglethorpe to SunTrust Bank, as trustee, relating to the Amendment of Section 9.9 of the Original Indenture. (Filed as Exhibit 4.7.1(ii) to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*4.7.1(jj)	–	Thirty-Fifth Supplemental Indenture, dated as of October 1, 2006, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Oglethorpe Power Corporation First Mortgage Bonds, Series 2006. (Filed as Exhibit 4.7.1(jj) to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*4.7.1(kk)	–	Thirty-Sixth Supplemental Indenture, dated as of October 1, 2006, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2006A (Burke) Note, Series 2006B-1 (Burke) Note, Series 2006B-2 (Burke) Note, Series 2006B-3 (Burke) Note, Series 2006B-4 (Burke) Note and Series 2006A (Monroe) Note. (Filed as Exhibit 4.7.1(kk) to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*4.7.1(ll)	–	Thirty-Seventh Supplemental Indenture, dated as of October 1, 2006, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2006C-1 (Burke) Note, Series 2006C-2 (Burke) Note and Series 2006B (Monroe) Note. (Filed as Exhibit 4.7.1(ll) to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*4.7.1(mm)		Thirty-Eighth Supplemental Indenture, dated as of May 1, 2007, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Amendments to the Retained Indebtedness Note. (Filed as Exhibit 4.7.1(mm) to the Registrant's Form 10-Q for the quarterly period ended June 30, 2007, File No. 33-7591.)
*4.7.1(nn)		Thirty-Ninth Supplemental Indenture, dated as of July 1, 2007, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2007 (FFB R-8) Note and Series 2007 (RUS R-8) Reimbursement Note. (Filed as Exhibit 4.7.1(nn) to the Registrant's Form 10-Q for the quarterly period ended June 30, 2007, File No. 33-7591.)
*4.7.1(oo)		Fortieth Supplemental Indenture, dated as of October 1, 2007, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Oglethorpe Power Corporation First Mortgage Bonds, Series 2007. (Filed as Exhibit 4.7.1(oo) to the Registrant's Form 10-Q for the quarterly period ended September 30, 2007, File No. 33-7591.)

99

*4.7.1(pp)		Forty-First Supplemental Indenture, dated as of October 1, 2007, made by Oglethorpe to U.S. Bank National Association, as trustee, relating to the Series 2007A (Appling) Note, Series 2007B (Appling) Note, Series 2007A (Burke) Note, Series 2007B (Burke) Note, Series 2007C (Burke) Note, Series 2007D (Burke) Note, Series 2007E (Burke) Note, Series 2007F (Burke) Note and Series 2007A (Monroe) Note. (Filed as Exhibit 4.7.1(pp) to the Registrant's Form 10-Q for the quarterly period ended September 30, 2007, File No. 33-7591.)
4.7.1(qq)	–	Forty-Second Supplemental Indenture, dated as of February 5, 2008, made by Oglethorpe to U.S. Bank National Association, as trustee, providing for the Amendment of Section 1.1 of the Original Indenture.
*4.7.2	–	Security Agreement, dated as of March 1, 1997, made by Oglethorpe to SunTrust Bank, Atlanta, as trustee. (Filed as Exhibit 4.8.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
4.8.1(1)	–	Loan Agreement, dated as of October 1, 1992, between Development Authority of Monroe County and Oglethorpe relating to Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 1992A.
4.8.2(1)	–	Note, dated October 1, 1992, from Oglethorpe to Trust Company Bank, as trustee acting pursuant to a Trust Indenture, dated as of October 1, 1992, between Development Authority of Monroe County and Trust Company Bank relating to Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 1992A.
4.8.3(1)	–	Trust Indenture, dated as of October 1, 1992, between Development Authority of Monroe County and Trust Company Bank, Trustee, relating to Development Authority of Monroe County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Scherer Project), Series 1992A.
4.9.1(1)	–	Loan Agreement, dated as of December 1, 1992, between Development Authority of Burke County and Oglethorpe relating to Development Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other substantially identical (Swap Bonds) loan agreement.
4.9.2(1)	–	Note, dated December 1, 1992, from Oglethorpe to Trust Company Bank, as trustee acting pursuant to a Trust Indenture, dated as of December 1, 1992, between Development Authority of Burke County and Trust Company Bank, relating to Development Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other substantially identical note.
4.9.3(1)	–	Trust Indenture, dated as of December 1, 1992, from Development Authority of Burke County to Trust Company Bank, as trustee, relating to Development Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other substantially identical trust indenture.
4.9.4(1)	–	Interest Rate Swap Agreement, dated as of December 1, 1992, by and between Oglethorpe and AIG Financial Products Corp. relating to Development Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other substantially identical agreement.
4.9.5(1)	–	Liquidity Guaranty Agreement, dated as of December 1, 1992, by and between Oglethorpe and AIG Financial Products Corp. relating to Development Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other substantially identical agreement.

100

4.9.6(1)	–	Standby Bond Purchase Agreement, dated as of December 1, 1998, between Oglethorpe and Bayerische Landesbank Girozentrale, and amended by the First Amendment to Standby Bond Purchase Agreement, dated as of November 1, 2002, relating to Development Authority of Burke County Adjustable Tender Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1993A, and one other substantially identical agreement.
4.10.1(1)	–	Loan Agreement, dated as of October 1, 2002, between Development Authority of Burke County and Oglethorpe relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2002A, and eight other substantially identical (Auction Rate Bonds) loan agreements.
4.10.2(1)	–	Note, dated October 23, 2002, from Oglethorpe to SunTrust Bank, as trustee pursuant to a Trust Indenture, dated as of October 1, 2002, between Development Authority of Burke County and SunTrust Bank relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2002A, and eight other substantially identical notes.
4.10.3(1)	–	Trust Indenture, dated as of October 1, 2002, between Development Authority of Burke County and SunTrust Bank, as trustee, relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 2002A, and eight other substantially identical indentures.
4.11.1(1)	–	Lease Agreement, dated as of August 1, 2003, between Development Authority of Heard County and Oglethorpe relating to Development Authority of Heard County Taxable Industrial Development Revenue Bonds (Oglethorpe Power Corporation Project), Series 2003, and four other substantially identical (Industrial Development Revenue Bonds) lease agreements.
4.11.2(1)	–	Guaranty Agreement, dated as of August 1, 2003, between Oglethorpe and SunTrust Bank, as trustee pursuant to an Indenture of Trust, dated as of August 1, 2003, between Development Authority of Heard County and SunTrust Bank relating to Development Authority of Heard County Taxable Industrial Development Revenue Bonds (Oglethorpe Power Corporation Project), Series 2003, and four other substantially identical guaranties.
4.11.3(1)	–	Indenture of Trust, dated as of August 1, 2003, between Development Authority of Heard County and SunTrust Bank, as trustee, relating to Development Authority of Heard County Taxable Industrial Development Revenue Bonds (Oglethorpe Power Corporation Project), Series 2003, and four other substantially identical indentures.
4.12.1(1)	–	Loan Agreement, dated as of March 1, 1998, between Development Authority of Burke County and Oglethorpe relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1998A, and twelve other substantially identical (Adjustable Rate Bonds) loan agreements.
4.12.2(1)	–	Note, dated March 17, 1998, from Oglethorpe to SunTrust Bank, Atlanta, as trustee pursuant to a Trust Indenture, dated as of March 1, 1998, between Development Authority of Burke County and SunTrust Bank, Atlanta relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1998A, and twelve other substantially identical notes.
4.12.3(1)	–	Trust Indenture, dated as of March 1, 1998, between Development Authority of Burke County and SunTrust Bank, Atlanta, as trustee, relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1998A, and twelve other substantially identical indentures.
4.12.4(1)	–	Standby Bond Purchase Agreement, dated March 17, 1998, between Oglethorpe and Coöperatieve Centrale Raiffeisen-Boerenleenbank B.A., "Rabobank Nederland," acting through its New York Branch, as amended on May 16, 2000 and July 22, 2002, relating to Development Authority of Burke County Pollution Control Revenue Bonds (Oglethorpe Power Corporation Vogtle Project), Series 1998A, and twelve other substantially identical standby liquidity agreements.

101

*4.13.1	–	Indemnity Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia Transmission Corporation (An Electric Membership Corporation). (Filed as Exhibit 4.13.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*4.13.2	–	Indemnification Agreement, dated as of March 11, 1997, by Oglethorpe and Georgia Transmission Corporation (An Electric Membership Corporation) for the benefit of the United States of America. (Filed as Exhibit 4.13.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
4.14.1(1)	–	Master Loan Agreement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB, MLA No. 0459.
4.14.2(1)	–	Consolidating Supplement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T1.
4.14.3(1)	–	Promissory Note, dated March 1, 1997, in the original principal amount of $7,102,740.26, from Oglethorpe to CoBank, ACB, relating to Loan No. ML0459T1.
4.14.4(1)	–	Consolidating Supplement, dated as of March 1, 1997, between Oglethorpe and CoBank, ACB, relating to Loan No. ML0459T2.
4.14.5(1)	–	Promissory Note, dated March 1, 1997, in the original principal amount of $1,856,475.12, made by Oglethorpe to CoBank, ACB, relating to Loan No. ML0459T2.
*10.1.1(a)	–	Participation Agreement No. 2 among Oglethorpe as Lessee, Wilmington Trust Company as Owner Trustee, The First National Bank of Atlanta as Indenture Trustee, Columbia Bank for Cooperatives as Loan Participant and Ford Motor Credit Company as Owner Participant, dated December 30, 1985, together with a Schedule identifying three other substantially identical Participation Agreements. (Filed as Exhibit 10.1.1(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(b)	–	Supplemental Participation Agreement No. 2. (Filed as Exhibit 10.1.1(a) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.1(c)	–	Supplemental Participation Agreement No. 1, dated as of June 30, 1987, among Oglethorpe as Lessee, IBM Credit Financing Corporation as Owner Participant, Wilmington Trust Company and The Citizens and Southern National Bank as Owner Trustee, The First National Bank of Atlanta, as Indenture Trustee, and Columbia Bank for Cooperatives, as Loan Participant. (Filed as Exhibit 10.1.1(c) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.1(d)	–	Second Supplemental Participation Agreement No. 2, dated as of December 17, 1997, among Oglethorpe as Lessee, DFO Partnership, as assignee of Ford Motor Credit Company, as Owner Participant, Wilmington Trust Company and NationsBank, N.A. as Owner Trustee, The Bank of New York Trust Company of Florida, N.A. as Indenture Trustee, CoBank, ACB as Loan Participant, OPC Scherer Funding Corporation, as Original Funding Corporation, OPC Scherer 1997 Funding Corporation A, as Funding Corporation, and SunTrust Bank, Atlanta, as Original Collateral Trust Trustee and Collateral Trust Trustee, with a Schedule identifying three substantially identical Second Supplemental Participation Agreements and any material differences. (Filed as Exhibit 10.1.1(d) to Registrant's Form S-4 Registration Statement, File No. 333-4275.)
*10.1.2	–	General Warranty Deed and Bill of Sale No. 2 between Oglethorpe, Grantor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Grantee, together with a Schedule identifying three substantially identical General Warranty Deeds and Bills of Sale. (Filed as Exhibit 10.1.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

102

*10.1.3(a)	–	Supporting Assets Lease No. 2, dated December 30, 1985, between Oglethorpe, Lessor, and Wilmington Trust Company and William J. Wade, as Owner Trustees, under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Lessee, together with a Schedule identifying three substantially identical Supporting Assets Leases. (Filed as Exhibit 10.1.3 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.3(b)	–	First Amendment to Supporting Assets Lease No. 2, dated as of November 19, 1987, together with a Schedule identifying three substantially identical First Amendments to Supporting Assets Leases. (Filed as Exhibit 10.1.3(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.3(c)	–	Second Amendment to Supporting Assets Lease No. 2, dated as of October 3, 1989, together with a Schedule identifying three substantially identical Second Amendments to Supporting Assets Leases. (Filed as Exhibit 10.1.3(c) to the Registrant's Form 10-Q for the quarterly period ended March 31, 1998, File No. 33-7591.)
*10.1.4(a)	–	Supporting Assets Sublease No. 2, dated December 30, 1985, between Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2 dated December 30, 1985, with Ford Motor Credit Company, Sublessor, and Oglethorpe, Sublessee, together with a Schedule identifying three substantially identical Supporting Assets Subleases. (Filed as Exhibit 10.1.4 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.4(b)	–	First Amendment to Supporting Assets Sublease No. 2, dated as of November 19, 1987, together with a Schedule identifying three substantially identical First Amendments to Supporting Assets Subleases. (Filed as Exhibit 10.1.4(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.1.4(c)	–	Second Amendment to Supporting Assets Sublease No. 2, dated as of October 3, 1989, together with a Schedule identifying three substantially identical Second Amendments to Supporting Assets Subleases. (Filed as Exhibit 10.1.4(c) to the Registrant's Form 10-Q for the quarterly period ended March 31, 1998, File No. 33-7591.)
*10.1.5(a)	–	Tax Indemnification Agreement No. 2, dated December 30, 1985, between Ford Motor Credit Company, Owner Participant, and Oglethorpe, Lessee, together with a Schedule identifying three substantially identical Tax Indemnification Agreements. (Filed as Exhibit 10.1.5 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.5(b)	–	Amendment No. 1 to the Tax Indemnification Agreement No. 2, dated December 17, 1997, between DFO Partnership, as assignee of Ford Motor Credit Company, as Owner Participant, and Oglethorpe, as Lessee, with a Schedule identifying three substantially identical Amendments No. 1 to the Tax Indemnification Agreements and any material differences. (Filed as Exhibit 10.1.5(b) to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*10.1.6	–	Assignment of Interest in Ownership Agreement and Operating Agreement No. 2, dated December 30, 1985, between Oglethorpe, Assignor, and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, Assignee, together with Schedule identifying three substantially identical Assignments of Interest in Ownership Agreement and Operating Agreement. (Filed as Exhibit 10.1.6 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.1.7(a)	–	Consent, Amendment and Assumption No. 2 dated December 30, 1985, among Georgia Power Company and Oglethorpe and Municipal Electric Authority of Georgia and City of Dalton, Georgia and Gulf Power Company and Wilmington Trust Company and William J. Wade, as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a Schedule identifying three substantially identical Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

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*10.1.7(b)	–	Amendment to Consent, Amendment and Assumption No. 2, dated as of August 16, 1993, among Oglethorpe, Georgia Power Company, Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Jacksonville Electric Authority, Florida Power & Light Company and Wilmington Trust Company and NationsBank of Georgia, N.A., as Owner Trustees under Trust Agreement No. 2, dated December 30, 1985, with Ford Motor Credit Company, together with a Schedule identifying three substantially identical Amendments to Consents, Amendments and Assumptions. (Filed as Exhibit 10.1.9(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.2.1	–	Section 168 Agreement and Election dated as of April 7, 1982, between Continental Telephone Corporation and Oglethorpe. (Filed as Exhibit 10.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.2.2	–	Section 168 Agreement and Election dated as of April 9, 1982, between Rollins, Inc. and Oglethorpe. (Filed as Exhibit 10.4 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(a)	–	Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(b)	–	Amendment to Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.8 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.1(c)	–	Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of July 1, 1986. (Filed as Exhibit 10.6.1(a) to the Registrant's Form 10-K for the fiscal year ended December 31, 1987, File No. 33-7591.)
*10.3.1(d)	–	Amendment Number Three to the Plant Robert W. Scherer Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of August 1, 1988. (Filed as Exhibit 10.6.1(b) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.3.1(e)	–	Amendment Number Four to the Plant Robert W. Scherer Units Number One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.1(c) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.3.2(a)	–	Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of May 15, 1980. (Filed as Exhibit 10.6.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.3.2(b)	–	Amendment to Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 30, 1985. (Filed as Exhibit 10.1.7 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

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*10.3.2(c)	–	Amendment Number Two to the Plant Robert W. Scherer Units Numbers One and Two Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of December 31, 1990. (Filed as Exhibit 10.6.2(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.3.3	–	Plant Scherer Managing Board Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia, City of Dalton, Georgia, Gulf Power Company, Florida Power & Light Company and Jacksonville Electric Authority, dated as of December 31, 1990. (Filed as Exhibit 10.6.3 to the Registrant's Form 10-Q for the quarterly period ended September 30, 1993, File No. 33-7591.)
*10.4.1(a)	–	Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.7.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.4.1(b)	–	Amendment Number One, dated January 18, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.1(c)	–	Amendment Number Two, dated February 24, 1977, to the Alvin W. Vogtle Nuclear Units Numbers One and Two Purchase and Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.7.4 to the Registrant's Form 10-K for the fiscal year ended December 31, 1986, File No. 33-7591.)
*10.4.2	–	Plant Alvin W. Vogtle Additional Units Ownership Participation Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of April 21, 2006. (Filed as Exhibit 10.4.4 to the Registrant's Form 8-K, filed April 27, 2006, File No. 33-7591.)
*10.4.3	–	Plant Alvin W. Vogtle Nuclear Units Amended and Restated Operating Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia, dated as of April 21, 2006. (Filed as Exhibit 10.4.3 to the Registrant's Form 8-K, filed April 27, 2006, File No. 33-7591.)
*10.5.1	–	Plant Hal Wansley Purchase and Ownership Participation Agreement between Georgia Power Company and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.5.2(a)	–	Plant Hal Wansley Operating Agreement between Georgia Power Company and Oglethorpe, dated as of March 26, 1976. (Filed as Exhibit 10.8.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.5.2(b)	–	Amendment, dated as of January 15, 1995, to the Plant Hal Wansley Operating Agreements by and among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia. (Filed as Exhibit 10.5.2(a) to the Registrant's Form 10-Q for the quarterly period ended September 30, 1996, File No. 33-7591.)
*10.5.3	–	Plant Hal Wansley Combustion Turbine Agreement between Georgia Power Company and Oglethorpe, dated as of August 2, 1982 and Amendment No. 1, dated October 20, 1982. (Filed as Exhibit 10.18 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.6.1	–	Edwin I. Hatch Nuclear Plant Purchase and Ownership Participation Agreement between Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

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*10.6.2	–	Edwin I. Hatch Nuclear Plant Operating Agreement between Georgia Power Company and Oglethorpe, dated as of January 6, 1975. (Filed as Exhibit 10.9.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.7.1	–	Rocky Mountain Pumped Storage Hydroelectric Project Ownership Participation Agreement, dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.)
*10.7.2	–	Rocky Mountain Pumped Storage Hydroelectric Project Operating Agreement, dated as of November 18, 1988, by and between Oglethorpe and Georgia Power Company. (Filed as Exhibit 10.22.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1988, File No. 33-7591.)
*10.8.1	–	Amended and Restated Wholesale Power Contract, dated as of January 1, 2003, between Oglethorpe and Altamaha Electric Membership Corporation, together with a schedule identifying 38 other substantially identical Amended and Restated Wholesale Power Contracts. (Filed as Exhibit 10.31.1 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2003, File No. 33-7591.)
*10.8.2	–	First Amendment to Amended and Restated Wholesale Power Contract, dated as of June 1, 2005, between Oglethorpe and Altamaha Electric Membership Corporation, together with a schedule identifying 37 other substantially identical First Amendments. (Filed as Exhibit 10.8.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2005, File No. 33-7591.)
*10.8.3	–	Amended and Restated Supplemental Agreement, dated as of January 1, 2003, by and among Oglethorpe, Altamaha Electric Membership Corporation and the United States of America, together with a schedule identifying 38 other substantially identical Amended and Restated Supplemental Agreements. (Filed as Exhibit 10.31.2 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2003, File No. 33-7591.)
*10.8.4	–	Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of January 1, 1997, by and among Georgia Power Company, Oglethorpe and Altamaha Electric Membership Corporation, together with a Schedule identifying 38 other substantially identical Supplemental Agreements. (Filed as Exhibit 10.8.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.5	–	Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of March 1, 1997, by and between Oglethorpe and Altamaha Electric Membership Corporation, together with a Schedule identifying 36 other substantially identical Supplemental Agreements, and an additional Supplemental Agreement that is not substantially identical. (Filed as Exhibit 10.8.4 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.6	–	Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of March 1, 1997, by and between Oglethorpe and Coweta-Fayette Electric Membership Corporation, together with a Schedule identifying 1 other substantially identical Supplemental Agreement. (Filed as Exhibit 10.8.5 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.8.7	–	Supplemental Agreement to the Amended and Restated Wholesale Power Contract, dated as of May 1, 1997 by and between Oglethorpe and Altamaha Electric Membership Corporation, together with a Schedule identifying 38 other substantially identical Supplemental Agreements. (Filed as Exhibit 10.8.6 to the Registrant's Form 10-Q for the quarterly period ended June 30, 1997, File No. 33-7591.)
*10.9(a)	–	Joint Committee Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and the City of Dalton, Georgia, dated as of August 27, 1976. (Filed as Exhibit 10.14(b) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)

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*10.9(b)	–	First Amendment to Joint Committee Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and the City of Dalton, Georgia, dated as of June 19, 1978. (Filed as Exhibit 10.14(a) to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.10	–	Letter of Commitment (Firm Power Sale) Under Service Schedule J – Negotiated Interchange Service between Alabama Electric Cooperative, Inc. and Oglethorpe, dated March 31, 1994. (Filed as Exhibit 10.11(b) to the Registrant's Form 10-Q for the quarter ended June 30, 1994, File No. 33-7591.)
*10.11.1	–	Assignment of Power System Agreement and Settlement Agreement, dated January 8, 1975, by Georgia Electric Membership Corporation to Oglethorpe. (Filed as Exhibit 10.20.1 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.11.2	–	Power System Agreement, dated April 24, 1974, by and between Georgia Electric Membership Corporation and Georgia Power Company. (Filed as Exhibit 10.20.2 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.11.3	–	Settlement Agreement, dated April 24, 1974, by and between Georgia Power Company, Georgia Municipal Association, Inc., City of Dalton, Georgia Electric Membership Corporation and Crisp County Power Commission. (Filed as Exhibit 10.20.3 to the Registrant's Form S-1 Registration Statement, File No. 33-7591.)
*10.12	–	ITSA, Power Sale and Coordination Umbrella Agreement between Oglethorpe and Georgia Power Company, dated as of November 12, 1990. (Filed as Exhibit 10.28 to the Registrant's Form 8-K, filed January 4, 1991, File No. 33-7591.)
*10.13	–	Second Amended and Restated Nuclear Managing Board Agreement among Georgia Power Company, Oglethorpe, Municipal Electric Authority of Georgia and City of Dalton, Georgia dated as of April 21, 2006. (Filed as Exhibit 10.13(b) to the Registrant's Form 8-K, filed April 27, 2006, File No. 33-7591.)
*10.14	–	Supplemental Agreement by and among Oglethorpe, Tri-County Electric Membership Corporation and Georgia Power Company, dated as of November 12, 1990, together with a Schedule identifying 38 other substantially identical Supplemental Agreements. (Filed as Exhibit 10.30 to the Registrant's Form 8-K, filed January 4, 1991, File No. 33-7591.)
*10.15	–	Power Purchase Agreement between Oglethorpe and Hartwell Energy Limited Partnership, dated as of June 12, 1992. (Filed as Exhibit 10.35 to the Registrant's Form 10-K for the fiscal year ended December 31, 1992, File No. 33-7591).
*10.16.1	–	Participation Agreement (P1), dated as of December 30, 1996, among Oglethorpe, Rocky Mountain Leasing Corporation, Fleet National Bank, as Owner Trustee, SunTrust Bank, Atlanta, as Co-Trustee, the Owner Participant named therein and Utrecht-America Finance Co., as Lender, together with a Schedule identifying five other substantially identical Participation Agreements. (Filed as Exhibit 10.32.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.2	–	Rocky Mountain Head Lease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Rocky Mountain Head Lease Agreements. (Filed as Exhibit 10.32.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.3	–	Ground Lease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Ground Lease Agreements. (Filed as Exhibit 10.32.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)

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*10.16.4	–	Rocky Mountain Agreements Assignment and Assumption Agreement (P1), dated as of December 30, 1996, between Oglethorpe and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Rocky Mountain Agreements Assignment and Assumption Agreements. (Filed as Exhibit 10.32.4 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.5	–	Facility Lease Agreement (P1), dated as of December 30, 1996, between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation, together with a Schedule identifying five other substantially identical Facility Lease Agreements. (Filed as Exhibit 10.32.5 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.6	–	Ground Sublease Agreement (P1), dated as of December 30, 1996, between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation, together with a Schedule identifying five other substantially identical Ground Sublease Agreements. (Filed as Exhibit 10.32.6 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.7	–	Rocky Mountain Agreements Re-assignment and Assumption Agreement (P1), dated as of December 30, 1996, between SunTrust Bank, Atlanta, as Co-Trustee and Rocky Mountain Leasing Corporation, together with a Schedule identifying five other substantially identical Rocky Mountain Agreements Re-assignment and Assumption Agreements. (Filed as Exhibit 10.32.7 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.8	–	Facility Sublease Agreement (P1), dated as of December 30, 1996, between Oglethorpe and Rocky Mountain Leasing Corporation, together with a Schedule identifying five other substantially identical Facility Sublease Agreements. (Filed as Exhibit 10.32.8 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.9	–	Ground Sub-sublease Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation and Oglethorpe, together with a Schedule identifying five other substantially identical Ground Sub-sublease Agreements. (Filed as Exhibit 10.32.9 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.10	–	Rocky Mountain Agreements Second Re-assignment and Assumption Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation and Oglethorpe, together with a Schedule identifying five other substantially identical Rocky Mountain Agreements Second Re-assignment and Assumption Agreements. (Filed as Exhibit 10.32.10 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.11	–	Payment Undertaking Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation and Coöperatieve Centrale Raiffeisen-Boerenleenbank B.A., New York Branch, as the Bank, together with a Schedule identifying five other substantially identical Payment Undertaking Agreements. (Filed as Exhibit 10.32.11 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.12	–	Payment Undertaking Pledge Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation, Fleet National Bank, as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Payment Undertaking Pledge Agreements. (Filed as Exhibit 10.32.12 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.13	–	Equity Funding Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation, AIG Match Funding Corp., the Owner Participant named therein, Fleet National Bank, as Owner Trustee, and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Equity Funding Agreements. (Filed as Exhibit 10.32.13 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)

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*10.16.14	–	Equity Funding Pledge Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Equity Funding Pledge Agreements. (Filed as Exhibit 10.32.14 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.15	–	Deed to Secure Debt, Assignment of Surety Bond and Security Agreement (P1), dated as of December 30, 1996, between Rocky Mountain Leasing Corporation, SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Collateral Assignment, Assignment of Surety Bond and Security Agreements. (Filed as Exhibit 10.32.15 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.16	–	Subordinated Deed to Secure Debt and Security Agreement (P1), dated as of December 30, 1996, among Oglethorpe, AMBAC Indemnity Corporation and SunTrust Bank, Atlanta, as Co-Trustee, together with a Schedule identifying five other substantially identical Subordinated Deed to Secure Debt and Security Agreements. (Filed as Exhibit 10.32.16 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.17	–	Tax Indemnification Agreement (P1), dated as of December 30, 1996, between Oglethorpe and the Owner Participant named therein, together with a Schedule identifying five other substantially identical Tax Indemnification Agreements. (Filed as Exhibit 10.32.17 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.18	–	Consent No. 1, dated as of December 30, 1996, among Georgia Power Company, Oglethorpe, SunTrust Bank, Atlanta, as Co-Trustee, and Fleet National Bank, as Owner Trustee, together with a Schedule identifying five other substantially identical Consents. (Filed as Exhibit 10.32.18 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.19(a)	–	OPC Intercreditor and Security Agreement No. 1, dated as of December 30, 1996, among the United States of America, acting through the Administrator of the Rural Utilities Service, SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet National Bank, as Owner Trustee, Utrecht-America Finance Co., as Lender and AMBAC Indemnity Corporation, together with a Schedule identifying five other substantially identical Intercreditor and Security Agreements. (Filed as Exhibit 10.32.19 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.16.19(b)	–	Supplement to OPC Intercreditor and Security Agreement No. 1, dated as of March 1, 1997, among the United States of America, acting through the Administrator of the Rural Utilities Service, SunTrust Bank, Atlanta, Oglethorpe, Rocky Mountain Leasing Corporation, SunTrust Bank, Atlanta, as Co-Trustee, Fleet National Bank, as Owner Trustee, Utrecht-America Finance Co., as Lender and AMBAC Indemnity Corporation, together with a Schedule identifying five other substantially identical Supplements to OPC Intercreditor and Security Agreements. (Filed as Exhibit 10.32.19(b) to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*10.17.1(a)	–	Member Transmission Service Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia Transmission Corporation (An Electric Membership Corporation). (Filed as Exhibit 10.33.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.17.1(b)	–	Agreement to Extend the Term of the Member Transmission Service Agreement, dated as of August 2, 2006, by and between Oglethorpe and Georgia Transmission Corporation (An Electric Membership Corporation). (Filed as Exhibit 10.17.1(b) to the Registrant's Form 10-Q for the quarterly period ended June 30, 2006, File No. 33-7591.)

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*10.17.2	–	Generation Services Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia System Operations Corporation. (Filed as Exhibit 10.33.2 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.17.3	–	Operation Services Agreement, dated as of March 1, 1997, by and between Oglethorpe and Georgia System Operations Corporation. (Filed as Exhibit 10.33.3 to the Registrant's Form 10-K for the fiscal year ended December 31, 1996, File No. 33-7591.)
*10.18	–	Long Term Transaction Service Agreement Under Southern Companies' Federal Energy Regulatory Commission Electric Tariff Volume No. 4 Market-Based Rate Tariff, between Georgia Power Company and Oglethorpe, dated as of February 26, 1999. (Filed as Exhibit 10.27 to the Registrant's Form 10-Q for the quarterly period ended March 31, 1999, File No. 33-7591.)
*10.19(3)	–	Employment Agreement, dated as of January 1, 2007, between Oglethorpe and Thomas A. Smith. (Filed as Exhibit 10.19 to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*10.20(3)	–	Employment Agreement, dated January 1, 2007, between Oglethorpe and Michael W. Price. (Filed as Exhibit 10.20 to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*10.21(3)	–	Employment Agreement, dated as of January 1, 2007, between Oglethorpe and Elizabeth Bush Higgins. (Filed as Exhibit 10.21 to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*10.22(3)	–	Employment Agreement, dated as of January 1, 2007, between Oglethorpe and Jami G. Reusch. (Filed as Exhibit 10.22 to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*10.23(3)	–	Employment Agreement, dated as of January 1, 2007, between Oglethorpe and William F. Ussery. (Filed as Exhibit 10.23 to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
*10.24(3)	–	Employment Agreement, dated as of January 1, 2007, between Oglethorpe and William Clay Robbins. (Filed as Exhibit 10.24 to the Registrant's Form 10-K for the fiscal year ended December 31, 2006, File No. 33-7591.)
10.25	–	Oglethorpe Power Corporation Executive Incentive Payment Plan, dated November 8, 2007.
*10.26	–	Participation Agreement for the Oglethorpe Power Corporation Executive Supplemental Retirement Plan, dated as of March 15, 2002, between Oglethorpe and Thomas A. Smith. (Filed as Exhibit 10.30 to the Registrant's Form 10-Q for the quarterly period ended March 31, 2002, File No. 33-7591.)
*10.27	–	Withdrawal Agreement, dated as of October 1, 2004, among Flint Electric Membership Corporation, Cobb Electric Membership Corporation and Oglethorpe. (Filed as Exhibit 10.31 to the Registrant's Form 8-K, filed October 7, 2004, File No. 33-7591.)
*14.1	–	Code of Ethics, dated November 11, 2003. (Filed as Exhibit 14.1 to the Registrant's Form 10-K for the fiscal year ended December 31, 2003, File No. 33-7591.)
21.1	–	Rocky Mountain Leasing Corporation, a Delaware corporation.
31.1	–	Rule 13a-14(a)/15d-14(a) Certification, by Thomas A. Smith (Principal Executive Officer).
31.2	–	Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins (Principal Financial Officer).
32.1	–	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Thomas A. Smith (Principal Executive Officer).
32.2	–	Certification Pursuant to 18 U.S.C. 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Elizabeth B. Higgins (Principal Financial Officer).
*99.1	–	Member Financial and Statistical Information (filed as Exhibit 99.1 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2007, File No. 33-7591.)

(1)

Pursuant to 17 C.F.R. 229.601(b)(4)(iii), this document(s) is not filed herewith; however the registrant hereby agrees that such document(s) will be provided to the Commission upon request.

(2)

Certain portions of this document have been omitted as confidential and filed separately with the Commission.

(3)

Indicates a management contract or compensatory arrangement required to be filed as an exhibit to this Report.

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SIGNATURES

       Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on the 26th day of March, 2008.

OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION)
By:	/s/  THOMAS A. SMITHTHOMAS A. SMITH President and Chief Executive Officer

    Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/  THOMAS A. SMITHTHOMAS A. SMITH	President and Chief Executive Officer (Principal Executive Officer)	March 26, 2008
/s/  ELIZABETH B. HIGGINSELIZABETH B. HIGGINS	Chief Financial Officer (Principal Financial Officer)	March 26, 2008
/s/  BRIAN PREVOSTBRIAN PREVOST	Vice President, Controller (Chief Accounting Officer)	March 26, 2008
/s/  C. HILL BENTLEYC. HILL BENTLEY	Director	March 26, 2008
/s/  LARRY N. CHADWICKLARRY N. CHADWICK	Director	March 26, 2008
/s/  BENNY W. DENHAMBENNY W. DENHAM	Director	March 26, 2008
/s/  WM. RONALD DUFFEYWM. RONALD DUFFEY	Director	March 26, 2008
/s/  M. ANTHONY HAMM. ANTHONY HAM	Director	March 26, 2008

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/s/  GARY A. MILLERGARY A. MILLER	Director	March 26, 2008
/s/  MARSHALL MILLWOODMARSHALL MILLWOOD	Director	March 26, 2008
/s/  JEFFREY W. MURPHYJEFFREY W. MURPHY	Director	March 26, 2008
/s/  J. SAM L. RABUNJ. SAM L. RABUN	Director	March 26, 2008
/s/  JOHN S. RANSONJOHN S. RANSON	Director	March 26, 2008
/s/  H. B. WILEY, JR.H. B. WILEY, JR.	Director	March 26, 2008
/s/  GARY W. WYATTGARY W. WYATT	Director	March 26, 2008

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    SUPPLEMENTAL INFORMATION TO BE FURNISHED WITH REPORTS FILED PURSUANT TO SECTION 15(d) OF THE ACT BY REGISTRANTS WHICH HAVE NOT REGISTERED SECURITIES PURSUANT TO SECTION 12 OF THE ACT.

    The registrant is a membership corporation and has no authorized or outstanding equity securities. Proxies are not solicited from the holders of Oglethorpe's public bonds. No annual report or proxy material has been sent to such bondholders.

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OGLETHORPE POWER CORPORATION 2007 FORM 10-K ANNUAL REPORT Table of Contents
SELECTED DEFINITIONS
PART I
OGLETHORPE POWER CORPORATION
OGLETHORPE'S POWER SUPPLY RESOURCES
THE MEMBERS AND THEIR POWER SUPPLY RESOURCES
ENVIRONMENTAL AND OTHER REGULATION
PART II
Index To Financial Statements
OGLETHORPE POWER CORPORATION CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES For the years ended December 31, 2007, 2006 and 2005
OGLETHORPE POWER CORPORATION CONSOLIDATED BALANCE SHEETS December 31, 2007 and 2006
OGLETHORPE POWER CORPORATION CONSOLIDATED STATEMENTS OF CAPITALIZATION December 31, 2007 and 2006
OGLETHORPE POWER CORPORATION CONSOLIDATED STATEMENTS OF CASH FLOWS For the years ended December 31, 2007, 2006 and 2005
OGLETHORPE POWER CORPORATION CONSOLIDATED STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND ACCUMULATED OTHER COMPREHENSIVE DEFICIT For the years ended December 31, 2007, 2006 and 2005
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS For the years ended December 31, 2007, 2006 and 2005
PART III
PART IV
SIGNATURES

EX-4.7.1(QQ)

EX-10.25

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EXHIBIT 10.25

OGLETHORPE POWER CORPORATION

EXECUTIVE INCENTIVE PAYMENT PLAN

        This is the amended and restated OGLETHORPE POWER CORPORATION EXECUTIVE INCENTIVE PAYMENT PLAN (the "Plan"), executed by Oglethorpe Power Corporation, a Georgia corporation (hereinafter the "Corporation"), this 8th day of November, 2007.

W I T N E S S E T H:

        WHEREAS, the Corporation desires to continue to provide incentives to one or more of its key executives to encourage them to remain in the employ of the Corporation; and

        WHEREAS, one of the means selected by the Corporation to offer such incentives is through the adoption of an unfunded nonqualified deferred compensation plan to benefit only a select group of management or highly compensated personnel; and

        WHEREAS, the Corporation desires to amend and restate the Plan to comply with changes in applicable law and regulations;

        NOW, THEREFORE, the Corporation hereby adopts the following amended and restated version of the Plan, effective as of January 1, 2008:

ARTICLE I
DEFINITIONS

        1.1    Definitions.    As used in this instrument, the following terms shall have the meaning hereinafter set forth:

        (a)   "Beneficiary" shall mean a person entitled to benefits hereunder as beneficiary of a deceased Participant or as beneficiary of a deceased Beneficiary.

        (b)   "Board" shall mean the Board of Directors of the Corporation.

        (c)   "Code" shall mean the Internal Revenue Code of 1986, as amended.

        (d)   "Committee" shall mean the duly appointed Compensation Committee of the Board of Directors.

        (e)   "Disability" shall have the same meaning as set forth in the Corporation's long-term disability group insurance program, as in effect from time to time.

        (f)    "Distribution Event" shall mean the Participant's retirement, death, disability, termination of employment or other event giving rise to the Participant's right to a distribution of all or a portion of his or her accrued benefits under this Plan, as more fully described in the Participation Agreement, which shall be consistent with the provisions of Section 409A of the Code.

        (g)   "Executive" shall mean any person employed by the Corporation who is identified by the Corporation as being a member of a select group of the Corporation's management.

        (h)   "Normal Retirement Age" shall mean age sixty-five (65).

        (i)    "Participant" shall mean any Executive who is designated by the Corporation as eligible to participate in the Plan and who actually participates in the Plan.

        (j)    "Participation Agreement" shall mean the agreement executed by the Corporation and the Participant, under which the Participant agrees to participate in the Plan and setting forth the terms of such participation, including, without limitation, the amount of deferred compensation to be contributed to the Plan, the applicable Distribution Events, the vesting and forfeiture provisions

and the term of such participation. Unless the Board of Directors shall otherwise direct, a Participation Agreement may be executed on behalf of the Corporation by the Chairman of the Board, the President and Chief Executive Officer or the Chief Operating Officer.

        (k)   "Plan" shall mean the Oglethorpe Power Corporation Executive Incentive Payment Plan set forth herein.

        1.2    Rules of Interpretation.

        (a)   Where necessary or appropriate to the meaning hereof, the singular shall be deemed to include the plural, the plural to include the singular, the masculine to include the feminine and neuter, the feminine to include the masculine and neuter, and the neuter to include the masculine and feminine.

        (b)   This Plan has been executed for the benefit of the Participants and their Beneficiaries, subject to the claims of the Corporation's creditors and other limitations set forth hereinabove. So far as possible, this Plan shall be interpreted and administered in a manner consistent with this intent and with the intention of the Corporation that this Plan shall at all times fully comply with the requirements of the law. The Corporation's reasonable determination of the interpretation of the provisions of this Plan shall be binding upon the Corporation, the Participants and Beneficiaries hereunder and all other persons.

ARTICLE II
ELIGIBILITY AND PARTICIPATION

        2.1    Eligibility.    No employee of the Corporation shall be eligible to participate in this Plan unless he or she is an Executive selected by the Board of Directors.

        2.2    Participation.    Each Executive selected to participate in the Plan shall enter the Plan immediately upon being designated and executing a Participation Agreement in such form as is required by the Corporation.

ARTICLE III
DEFERRED COMPENSATION,
INVESTMENTS AND FORFEITURES

        3.1    Participant Accounts.

        (a)   The Corporation shall cause an account to be kept in the name of each Participant which shall reflect the value of the deferred payments, designating what portion is vested and nonvested from time to time. Until and except to the extent that deferred compensation hereunder is distributed to or vested in a Participant (or Beneficiary) from time to time in accordance with the Participation Agreement and orders of the Corporation, the interest of each Participant and Beneficiary therein shall be contingent only. The account of a Participant, even if vested, shall be subject to forfeiture as provided in the Participation Agreement.

        (b)   Title to and beneficial ownership of any assets, whether cash or investments, which the Corporation may set aside or earmark to meets its deferred compensation obligations hereunder, shall at all times remain in the Corporation; and no Participant or Beneficiary shall under any circumstances acquire any property interest in any specific assets of the Corporation. To the extent that any person acquires a right to receive a distribution from the Corporation under this Plan, such right shall be no greater than the right of any unsecured general creditor of the Corporation. Hence the right of a Participant or Beneficiary to receive a distribution from the Plan shall be an unsecured claim against the general assets of the Corporation, and neither the Participant nor Beneficiary shall have any rights in or against any specific assets of the Corporation. All amounts credited to a Participant's account hereunder shall constitute general assets of the Corporation and

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may be disposed of by the Corporation at such times and for such purposes as it may deem appropriate.

        3.2    Setting Aside of Assets to Meet the Corporation's Plan Obligations.    In order to meet its deferred obligations hereunder, the Corporation shall each year set aside or earmark funds in an amount equal to the total amounts allocated and deferred for such year under this Article III

        3.3    Investment of Funds.

        (a)   Funds set aside or earmarked to meet the Corporation's deferred obligation hereunder may be kept in cash, or invested and reinvested, in the discretion of the Corporation. The Corporation may permit the Participant to suggest or direct the investment of such funds, but ownership of the funds shall remain with the Corporation, and the investment authority given to a Participant shall not constitute an incident of ownership with respect to such investments. The degree of authority over investment decisions shall be set forth in the Participation Agreement.

        (b)   Except as provided in paragraphs (a) and (d) of this Section 3.3, and as otherwise permitted in the Participation Agreement, the investment of funds set aside or earmarked to meet the Corporation's obligations hereunder shall generally be made in stocks, bonds, insurance policies or other assets selected by the Committee in its sole discretion; provided, however, that no portion of such funds shall be invested in any securities of the Corporation or any of its affiliates. In the exercise of the foregoing discretionary investment powers, the Committee may engage investment counsel, and, if it so desires, may delegate to such counsel full or limited authority to select the securities in which the funds are to be invested. The cost of any such service shall be charged as an expense of administering the Plan and paid from the invested funds unless otherwise provided in the Participation Agreement.

        (c)   The income and gains and losses, both realized and unrealized, from investments made pursuant to paragraph (b), net of any expenses properly chargeable thereto, shall be determined at least annually at the close of the year by the Corporation. An amount equal to the net income or loss as so determined shall be allocated among the accounts of the Participants concerned in proportion to the values of their accounts at the beginning of the year or as may otherwise be appropriate. Amounts so allocated shall increase or decrease, as the case may be, the future benefits receivable by such Participants or their Beneficiaries.

        (d)   In the event a Distribution Event occurs and the deferred benefits are to be paid in installments rather than in a lump sum, the Corporation shall set aside funds in an amount equal to the unpaid balance of such obligation. Funds to set aside may be kept in cash, or invested and reinvested in the discretion of the Corporation, except that the Corporation may permit the Participant to indicate how such funds are to be invested (including investment in money market or savings accounts or bonds). The total amount payable to the Participant shall be appropriately adjusted by an amount equal to the net income or loss on such funds, determined in accordance with the principles of paragraphs (b) and (c) above.

        3.4    Distribution Events.    The Corporation shall determine and set forth, in a Participant's Participation Agreement, the Distribution Event or Events applicable to such Participant, consistent with the distribution events set forth in Code Section 409A. In no event shall the Participation Agreement set forth a distribution event that is not permitted under Code Section 409A. Upon the occurrence of a Distribution Event, the Corporation shall determine the benefits payable to the Participant or his or her Beneficiary, using the last available value of each of such assets. The last available value shall be determined by reference to the regularity and frequency of valuation of particular assets, such as daily valuation of marketable securities or periodic valuations of real estate. The amount of benefits so determined shall then be paid to the Participant or Beneficiary in cash or other property according to the terms of the Participation Agreement.

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        3.5    Beneficiaries.    Each Participant shall have the right to designate beneficiaries who are to succeed to his or her contingent right to receive future payments hereunder in the event of his or her death, pursuant to the provisions set forth in Article V of this Plan. A beneficiary may also designate beneficiaries with respect to his or her interest in any benefits to be paid hereunder.

        3.6    Forfeitures.    The right of a Participant or Beneficiary to receive a payment of deferred benefits under this Plan, even if such right is otherwise fully vested, shall be forfeited upon the occurrence of any of the events of forfeiture set forth in the Participation Agreement.

        3.7    No Fiduciary Relationship.    Nothing contained herein shall be deemed to create a trust of any kind or create any fiduciary relationship. Funds invested hereunder shall continue for all purposes to be a part of the general funds of the Corporation, and no person other than the Corporation shall by virtue of the provisions of this Plan have any interest in such funds.

ARTICLE IV
ADMINISTRATION

        4.1    Plan Administrator.    The Corporation is the plan administrator and has the authority to control and manage the operation and administration of the Plan. The Corporation shall make such rules, regulations, interpretations, and shall take such other actions to administer the Plan as the Corporation may deem appropriate. In administering the Plan, the Corporation shall act in a nondiscriminatory manner with respect to Participants and Beneficiaries.

        4.2    Delegation of Authority.    The Board of Directors may delegate any administrative duties of the Corporation hereunder to its designee. Unless the Board of Directors shall determine otherwise, all actions that could otherwise be taken by the Board of Directors hereunder may be and shall be taken by the Committee. Whenever action is required by the Corporation hereunder, the same may be taken by any individual designated by the Committee as agent for the purpose. Should it become necessary to perform some act hereunder and there is no direction in this Plan, the Corporation shall exercise its discretion in a manner that is consistent with the purpose of this Plan; and in so acting the Corporation and its agents shall be fully protected and shall be absolved from all liability except from fraud or bad faith. With respect to the initial administration of the Plan, the Board of Directors delegates to Jami Reusch and Homerzelle Gentry all duties with respect to the daily administration of the Plan and its installation. The signature of both of them shall be sufficient to bind the Corporation in connection with the administration of the Plan, including the establishment of any and all corporate accounts with Salomon Smith Barney or any other entity for the holding and investment of any assets earmarked pursuant to this Plan, including the execution of client agreements and any and all other documents, and the taking of any and all actions, that they deem necessary or appropriate to ensure the efficient administration of this Plan.

        4.3    Records and Expenses.    The books and records to be maintained for the purpose of the Plan shall be maintained by the officers and employees of the Corporation at its expense and subject to the supervision and control of the Board of Directors. All the expenses of administering the Plan, shall be paid by the Corporation either from funds set aside or earmarked under the Plan or from other funds.

        4.4    Absence of Liability.    No member of the Board or of the Committee and no officer or employee of the Company shall be liable to any person for any action taken or omitted in connection with the administration of this Plan unless attributable to his or her own fraud or willful misconduct; nor shall the Corporation be liable to any person for any such action unless attributable to fraud or willful misconduct on the part of a director, officer or employee of the Corporation.

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ARTICLE V
DISTRIBUTIONS

        5.1    Distribution of Accounts.    In the event of the occurrence of a Distribution Event, as set forth in the Participation Agreement, with Distribution Events typically including the termination of a Participant's employment, whether such termination shall occur by reason of death, Disability, retirement or other separation from service (according to applicable regulations and rulings) (except with respect to a key employee of a corporation any stock of which is publicly traded on an established securities market, or otherwise, as more specifically described in Section 409A of the Code and Treasury Regulations Section 1.409A-1(i)); then the amount standing to such person's account in the Plan shall be distributed to or on behalf of such Participant at such time or times and in the manner provided under the terms of the Participation Agreement. No Participation Agreement shall set forth a Distribution Event that is not otherwise permitted under Code Section 409A.

        5.2    Form of Payment.    Distribution of benefits shall be made in a lump sum except as otherwise provided in the Participation Agreement or in the following sentence. Unless the Participation Agreement provides otherwise, in the event a Participant terminates employment (a) after attainment of the Normal Retirement Age, or (b) as a result of a Disability, he or she shall be paid the value of his or her account in five (5) annual installments commencing within sixty (60) days after the Distribution Event.

        5.3    Death Benefits; Beneficiary Designation; Distribution of Death Benefits.

        (a)   If a Participant or Beneficiary dies prior to receiving all of his or her account balance hereunder, then unless the Participation Agreement provides otherwise, the Participant's or Beneficiary's remaining account balance shall be paid to the Participant's or Beneficiary's designated Beneficiary in five (5) equal, annual installments commencing ninety (90) days after the Participant's or Beneficiary's death, as the case may be. Notwithstanding the foregoing, each annual installment payable to a Beneficiary shall be no less than Five Thousand Dollars ($5,000) (or the Participant's remaining account balance, if it is less than $5,000).

        (b)   At any time and from time to time, each Participant and each Beneficiary who is receiving payments hereunder shall have the unrestricted right to designate the person who, as his or her beneficiary, shall receive the amount payable hereunder after his or her death, and the right to revoke any such designations. Each such designation shall be evidenced by a written instrument filed with the Corporation, signed by the Participant or Beneficiary who is making the designation. No designation of beneficiaries shall be valid unless in writing signed by the Participant, dated, and filed with the Committee. Beneficiaries may be changed without the consent of any prior beneficiaries. In the event a Participant dies without having filed a beneficiary designation form with the Corporation, his or her deferred benefits payable hereunder shall be paid in the following order: (a) to the Participant's spouse; (b) if there is no surviving spouse, then to the Participant's children, in equal shares (with adopted children being treated as children for purposes of this Plan); and (c) if there are no surviving children, then to the Participant's estate.

        (c)   In the event that all, or any portion, of the distribution payable to a Participant or a Beneficiary hereunder shall, at the expiration of three years after it shall become payable, remain unpaid solely by reason of the inability of the Corporation, after sending a registered letter, return receipt requested, to the last known address, and after further diligent effort, to ascertain the whereabouts of such Participant or Beneficiary, the amount so distributable shall be forfeited.

        (d)   In the event that a Participant or Beneficiary shall elect to make a change in the timing or method of distribution, such change shall result in an automatic delay of five years in the commencement date of such distribution, as required by Code Section 409A.

        (1)   the Participant's separation from service

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        (2)   the date of the Participant's Disability, as hereinafter defined. The term Disability means that the Participant (I) is unable to engage in any substantial gainful activity by reason of any medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of no fewer than twelve months, or (II) is, by reason of any medically determinable physical or mental impairment that can be expected to result in death or to last for a continuous period of not less than twelve months, receiving income replacement benefits for a period of no fewer than three months under an accident and health plan covering employees of the Corporation;

        (3)   the Participant's death;

        (4)   a specified time (or pursuant to a fixed schedule) that is set forth under the Plan at the date of the deferral of such compensation;

        (5)   to the extent permitted under regulations, a change in the ownership or effective control of the Corporation, or in the ownership of a substantial portion of the Corporation's assets; or

        (6)   the occurrence of an Unforeseeable Emergency, as hereinafter defined. The term "Unforeseeable Emergency" means a severe financial hardship to the Participant resulting from an illness or accident suffered by the Participant, the Participant's spouse or the Participant's dependent (as defined in Code Section 152(a)), loss of the Participant's property due to casualty, or other similar extraordinary and unforeseeable circumstances arising from events beyond the control of the Participant. No distribution due to an Unforeseeable Emergency shall exceed the amounts necessary to satisfy such emergency plus amounts necessary to pay taxes reasonably anticipated as the result of such distribution, after taking into account the extent to which such hardship is or may be relieved through reimbursement or compensation by insurance or otherwise or by liquidation of the Participant's assets (to the extent the liquidation of such assets would not itself cause severe financial hardship) or by the cessation of deferrals under this Plan.

        (b)   There shall be no deemed separation from service if the Participant is on military leave, sick leave or other bona fide leave of absence, if the period of such leave does not exceed six months, or, if longer, so long as the individual's right to reemployment with the Corporation is provided either by statute or by contract. If the period of leave exceeds six months and the Participant's right to reemployment is not provided either by statute or by contract, the employment relationship is deemed to terminate on the first date immediately following such six-month period.

        (c)   The Participant shall make complete a distribution election form at the time of his or her initial participation in the Plan.

        (d)   Form of payment: Distributions shall be in form of a single lump sum or in the number of installments elected by the Participant. Installment payments shall begin not later than the later of the Participant's termination of services or April 1 of the year after the Participant attains age 70¹/2. Once commenced, the number of installments shall not be changed or accelerated, except as otherwise permitted under Treasury regulations. The number of installments shall be such as to qualify under Section 401(a)(9) of the Code. Payments shall be made at such time and in such manner as provided in distribution forms provided by the Corporation.

        (e)   Death of the Participant prior to full distribution. If a Participant should die before distribution of the full amount of the account described in this Plan has been made to the Participant, any remaining amounts shall be distributed to the Participant's beneficiary by the method designated by the Participant on distribution forms provided by the Corporation. The Participant may designate a payment to the beneficiary of a lump sum or the continued payment

6

of the Participant's elected number of installments to the beneficiary (if payment has begun). If a Participant has not designated a beneficiary, or if no designated beneficiary is living on the date of distribution, the amount credited to the account shall be distributed to the Participant's spouse, and if the Participant shall have no living spouse, to the Participant's children in equal shares per stirpes, and if the Participant shall have no living children, then to the Participant's estate, in a lump sum distribution as soon as administratively feasible following the Participant's death. The Participant may change the designation of beneficiary and the method of distribution in writing delivered to the Corporation before termination of services to the Corporation.

        (f)    Earnings and losses shall continue to be credited to the funds remaining in the account as if the Participant had not terminated services with the Corporation. Each installment payment shall be based on the amount then credited to the Participant's account. The final installment will be the balance of the account and any earnings or losses credited to such date.

ARTICLE VI
SPENDTHRIFT PROVISIONS AND OTHER PARTICIPANT RIGHTS

        6.1    Spendthrift Clause.    No interest of any person or entity in, or right to receive a distribution under, the Plan shall be subject in any manner to sale, transfer, assignment, pledge, attachment, garnishment or other alienation or encumbrance of any kind; nor may such interest or right to receive a distribution be taken, either voluntarily or involuntarily for the satisfaction of the debts of, or other obligations or claims against, such person or entity, including claims for alimony, support, separate maintenance and claims in bankruptcy proceedings. A distribution by the estate of a deceased Participant or Beneficiary to an heir or legatee of a right to receive payments hereunder shall not be deemed an alienation, assignment or anticipation for purposes of this Section 6.1.

        6.2    No Guarantee of Benefits.    Nothing contained in the Plan shall constitute a guarantee by the Corporation or any other person or entity that the assets of the Corporation will be sufficient to pay any benefits hereunder.

        6.3    No Guarantee of Employment.    Participating in this Plan shall not give any Participant any right to be retained in the service of the Corporation or any right or claim to any benefits hereunder unless such benefits have accrued under the terms and provisions of this Plan.

        6.4    Unclaimed Benefit.    Each Participant shall keep the Corporation informed of his or her current address and the current address of each Beneficiary. The Corporation shall not be obligated to search for the whereabouts of any person. If the location of a Participant or a Beneficiary is not made known to the Corporation within seven (7) years after the occurrence of a Distribution Event, then the Corporation shall have no further obligation to pay any benefit hereunder to such Participant or Beneficiary or anyone claiming under such Participant or Beneficiary, and such benefit shall be irrevocably forfeited.

ARTICLE VII
AMENDMENT AND TERMINATION

        7.1    Right to Amend.    The Corporation reserves the right by action of its Board of Directors to amend this Plan at any time or times. Any amendment which is necessary to bring this Plan into conformity with applicable government laws or regulations may be made retroactively.

        7.2    Termination.    The Corporation has established this Plan with the bona fide intention and expectation that it will be continuing and permanent. However, the Corporation reserves the right to terminate the Plan when, in the sole opinion of the Company, such termination is advisable.

        7.3    Effect of Amendment or Termination.    No amendment or termination shall directly or indirectly reduce the balance of any account held hereunder as of the effective date of such

7

amendment or termination. Upon termination of the Plan, there shall be paid to each Participant and each Beneficiary the amount of his or her account in the Plan, in accordance with the further terms of this Plan.

ARTICLE VIII
GENERAL PROVISIONS

        8.1    Claims Procedure.    The Corporation shall make a determination as to the right of any person to a benefit, and shall afford any person dissatisfied with such determination the right to a hearing thereon. Any denial by the Corporation of the claim for benefits under the Plan by a Participant or Beneficiary shall be stated in writing by the Corporation and delivered or mailed to the Participant or Beneficiary, and such notice shall set forth the specific reasons for the denial, written to the best of the Corporation's ability in a manner that may be understood without legal or actuarial counsel. In addition, the Corporation shall afford a reasonable opportunity to any Participant whose claim for benefits has been denied for a full and fair review of the decision denying the claim.

        8.2    Adoption of Plan by Successor.    In the event of the merger or consolidation of the Corporation, or the transfer of the assets of the Corporation to another corporation, association, partnership, sole proprietorship, or business organization, the Plan may be adopted by the surviving corporation, association, partnership, sole proprietorship, or other business organization which employs a substantial number of the Participants of the Plan. Such adoption of the Plan shall be expressed in an agreement between such surviving or other corporation, association, partnership, sole proprietorship, or business organization and the Committee under which such other corporation, association, partnership, sole proprietorship, or business organization adopts the Plan with respect to the Participants employed by it. If, pursuant to the terms hereof, the Plan is adopted by any other corporation, association, partnership, sole proprietorship, or business organization, such other corporation, association, partnership, sole proprietorship or business organization shall be deemed to succeed to the position of the Corporation under the Plan. If the Plan is not so adopted, then it shall be deemed terminated. The failure of any Participant hereunder to become an employee of such other corporation, association, partnership, sole proprietorship, or business organization shall constitute a Distribution Event.

        8.3    Governing Laws.    This Plan shall be construed and enforced under the laws of the State of Georgia, and all provisions hereof shall be administered in accordance with the provisions of the laws of the State of Georgia, provided that in case of conflict between Georgia law and any applicable and binding provision of the Code, particularly Section 409A thereof, or the Employee Retirement Income Security Act of 1974, as amended ("ERISA"), the provisions of the Code or ERISA shall control.

        8.4    Alternative Acts.    In the event it becomes impossible for the Corporation to perform any act required by this Plan, then the Corporation may perform such alternative act which most nearly carries out the intent and purpose of this Plan.

        8.5    Title Headings.    The headings in this Plan are solely for the convenience of reference and shall not affect its interpretation.

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        IN WITNESS WHEREOF, this Executive Incentive Payment Plan is signed by the Corporation through its duly authorized officer on the day and year first above written.

OGLETHORPE POWER CORPORATION
By:	/s/ Benny W. Denham Chairman of the Board of Directors

Attest:	/s/ Patricia N. Nash Patricia N. Nash, Assistant Secretary
	(CORPORATE SEAL)

9

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EXHIBIT 10.25

EX-31.1

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EXHIBIT 31.1

Rule 13a-14(a)/15d-14(a) Certification, by Thomas A. Smith
(Principal Executive Officer)

I, Thomas A. Smith, certify that:

        1.     I have reviewed this annual report on Form 10-K of Oglethorpe Power Corporation (An Electric Membership Corporation);

        2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

        3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

        4.     The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

        5.     The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 26, 2008

/s/ Thomas A. Smith Thomas A. Smith
President and Chief Executive Officer
(Principal Executive Officer)

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EXHIBIT 31.1

EX-31.2

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EXHIBIT 31.2

Rule 13a-14(a)/15d-14(a) Certification, by Elizabeth B. Higgins
(Principal Financial Officer)

I, Elizabeth B. Higgins, certify that:

1.

I have reviewed this annual report on Form 10-K of Oglethorpe Power Corporation (An Electric Membership Corporation);



2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;



3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;



4.

The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:



(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;



(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;



(c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and



(d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and



5.

The registrant's other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):



(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 26, 2008

/s/ Elizabeth B. Higgins Elizabeth B. Higgins
Chief Financial Officer
(Principal Financial Officer)

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EXHIBIT 31.2

EX-32.1

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EXHIBIT 32.1

Certification Pursuant to 18 U.S.C. 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2007 (the "Report") of Oglethorpe Power Corporation (the "Registrant"), as filed with the Securities and Exchange Commission on the date hereof, I, Thomas A. Smith, the President and Chief Executive Officer of the Registrant hereby certify, to the best of my knowledge, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and



(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Thomas A. Smith Thomas A. Smith
President and Chief Executive Officer

March 26, 2008 Date

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EXHIBIT 32.1

Certification Pursuant to 18 U.S.C. 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

EX-32.2

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EXHIBIT 32.2

Certification Pursuant to 18 U.S.C. 1350
As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

        In connection with the Annual Report on Form 10-K for the fiscal year ended December 31, 2007 (the "Report") of Oglethorpe Power Corporation (the "Registrant"), as filed with the Securities and Exchange Commission on the date hereof, I, Elizabeth B. Higgins, the Chief Financial Officer of the Registrant hereby certify, to the best of my knowledge, that:

(1)

The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and



(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Registrant.

/s/ Elizabeth B. Higgins Elizabeth B. Higgins
Chief Financial Officer

March 26, 2008 Date

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EXHIBIT 32.2

Certification Pursuant to 18 U.S.C. 1350 As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002