Oglethorpe Power 10K 2005 Annual report

Oglethorpe Power 10-K2005 FY Annual report

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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, 2005
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, or a non-accelerated filer. See definition of "accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.Large accelerated filero Accelerated filero Non-accelerated filerý

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

2005 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	18
1B	Unresolved Staff Comments	21
2	Properties	22
3	Legal Proceedings	27
4	Submission of Matters to a Vote of Security Holders	27
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	44
8	Financial Statements and Supplementary Data	48
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	74
9A	Controls and Procedures	74
9B	Other Information	74
PART III
10	Directors and Executive Officers of the Registrant	75
11	Executive Compensation	79
12	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	81
13	Certain Relationships and Related Transactions	81
14	Principal Accountant Fees and Services	81
PART IV
15	Exhibits and Financial Statement Schedules	83
	SIGNATURES	98

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

PART I

ITEM 1. BUSINESS

OGLETHORPE POWER CORPORATION

General

Oglethorpe Power Corporation (An Electric Membership Corporation) ("Oglethorpe") is a Georgia electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta. Oglethorpe is owned by 38 retail electric distribution cooperative members (the "Members"). Oglethorpe's principal business is providing wholesale electric power to the Members. As with cooperatives generally, Oglethorpe operates on a not-for-profit basis. Oglethorpe is the largest electric cooperative in the United States in terms of operating revenues, assets, kilowatt-hour ("kWh") sales and, through the Members, consumers served. Oglethorpe has 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 1.6 million electric consumers (meters) representing approximately 3.7 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 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 requirements above their Oglethorpe purchase obligations with purchases from other suppliers. (See "THE MEMBERS AND THEIR POWER SUPPLY RESOURCES – Member Power Supply Resources.")

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

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

In 2005, three of Oglethorpe's Members, Jackson EMC, Cobb EMC and Sawnee EMC, accounted for 13.0%, 12.8% and 10.4% of Oglethorpe's total revenues, respectively. None of the other Members accounted for as much as 10% of Oglethorpe's total revenues in 2005.

Wholesale Power Contracts

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

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

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

Under the Wholesale Power Contracts, Oglethorpe is not obligated to provide all of the Members' capacity and energy requirements. Individual Members must satisfy all of their requirements above their Oglethorpe purchase obligations from other suppliers, unless Oglethorpe and the Members agree that Oglethorpe will supply additional capacity and associated energy, subject to the approval requirements described above. In 2005, Oglethorpe supplied energy sufficient to meet approximately 70% 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

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

Oglethorpe may not provide services unrelated to its resources or its functions under the Wholesale Power Contracts if such services would require it to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of Oglethorpe's Board of Directors, 75% of the Members, and Members representing 75% of the patronage capital of Oglethorpe. Oglethorpe may provide any other such service to a Member so long as (1) doing so would not create a conflict of interest with respect to other Members, (2) such service is being provided to all Members or (3) such service has received the three-part 75% approval described above.

Electric Rates

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

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

•: 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
•: 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
•: 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").

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 small amount of loans (less than $8 million) to GSOC and also has secondary liability on a small amount of GSOC indebtedness and GSOC contractual obligations.

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 recent budgetary pressures faced by Congress. Because of these factors, Oglethorpe cannot predict the amount or cost of RUS-guaranteed loans that may be available to Oglethorpe in the future.

Oglethorpe has a loan contract with RUS in connection with the Mortgage Indenture. Under the loan contract, RUS has approval rights over certain

significant actions and arrangements, including, without limitation,

•: significant additions to or dispositions of system assets,
•: significant power purchase and sale contracts,
•: changes to the Wholesale Power Contracts and the rate schedule contained therein,
•: changes to plant ownership and operating agreements, and
•: in limited circumstances, issuance of additional secured debt.

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

Relationship with GPC

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

Competition

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

•: power marketing arrangements or other alliance arrangements;
•: whether potential load fluctuation risks in a competitive retail environment can be shifted to other wholesale suppliers;
•: whether power supply requirements will continue to be met by the current mix of ownership and purchase arrangements;
•: potential participation in future power supply resources, and whether they will be owned by Oglethorpe or by other entities;
•: whether disposition of existing assets or asset classes would be advisable;
•: sale of surplus SO₂ emission allowances;
•: extensions of nuclear facility licenses;
•: ways to extend the maturity of existing indebtedness;
•: potential prepayment of debt;
•: various responses to the proliferation of non-core services offered by electric utilities;
•: mergers or other combinations among distributors or power suppliers; and
•: other regulatory and business changes that may affect relative values of generation classes or have impacts on the electric industry.

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

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

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

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

From time to time, individual Members may be approached by parties indicating an interest in purchasing their systems. The Wholesale Power Contracts provide that a Member may not dissolve, liquidate or otherwise wind up its affairs without Oglethorpe's approval. A Member generally must obtain approval from Oglethorpe before it may consolidate or merge with any person or reorganize or change the form of its business organization from an electric membership corporation or sell, transfer, lease or otherwise dispose of all or substantially all of its assets to any person, whether in a single transaction or series of transactions. The Member may enter such a transaction without Oglethorpe's approval if specified conditions are satisfied, including, but not limited to, an agreement by the transferee, satisfactory to Oglethorpe, to assume the obligations of the Member under the Wholesale Power Contract, and certifications of accountants as to certain specified financial requirements of the transferee.

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

of Pataula EMC's payment obligations under its Wholesale Power Contract. Other Members could 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 substantial portion of their requirements from a combination of its generating assets and power purchased from other suppliers.

Generating Plants

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

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

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

Power Purchase and Sale Arrangements

Power Purchases

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

Oglethorpe has a contract through 2019 to purchase approximately 300 MW of capacity from Hartwell Energy Limited Partnership, a joint venture between Centennial Energy Resources, LLC, a subsidiary of MDU Resources Inc., and American National Power, Inc., a subsidiary of National Power, PLC. This

capacity is provided by two 150 MW gas-fired combustion turbine generating units on a site near Hartwell, Georgia. Oglethorpe has the right to dispatch the units.

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

In addition, Oglethorpe also purchases small amounts of capacity and energy from "qualifying facilities" under the Public Utility Regulatory Policies Act of 1978 ("PURPA"). Under a waiver order from the Federal Energy Regulatory Commission ("FERC"), Oglethorpe historically made all purchases the Members would have otherwise been required to make under PURPA and Oglethorpe was relieved of its obligation to sell certain services to "qualifying facilities" so long as the Members make those sales. Purchases by Oglethorpe from such qualifying facilities provided less than 0.1% of Oglethorpe's energy requirements for the Members in 2005. 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 60 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-fourth of these agreements, primarily to facilitate the short-term management of its resource portfolio.

Future Power Resources

In May 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% of any new project. Although preliminary decisions may be made over the next two years, the extent of Oglethorpe's ultimate involvement, if any, will not be determined for two to four years. The co-owners have negotiated participation agreements that, upon execution, would govern the rights and obligations of co-owners of the additional units. The effectiveness of these agreements with respect to Oglethorpe will be subject to RUS approval. Oglethorpe is currently participating with the co-owners in the costs of pursuing this option, including preparation of applications to the NRC for the appriopriate permits and licenses. Oglethorpe may ultimately elect not to participate in any unit that may be constructed, or elect to participate at less than its current 30% participation. To the extent it 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"). Any request by Members for Oglethorpe to acquire a new power supply resource must be approved in accordance with the Wholesale Power Contracts.

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 1.6 million electric consumers (meters) representing approximately 3.7 million people. The Members serve a region covering approximately 37,000 square miles, which is approximately 65% of the land area in the State of Georgia, encompassing 150 of the State's 159 counties. Sales by the Members in 2005 amounted to approximately 32 million megawatt hours ("MWh"), with approximately 66% to residential consumers, 30% to commercial and industrial consumers and 4% to other consumers. The Members are the principal suppliers for the power needs of rural Georgia. While the Members do not serve any major cities, portions of their service territories are in close proximity to urban areas and are experiencing substantial growth due to the expansion of urban areas, including metropolitan Atlanta, into suburban areas and the growth of suburban areas into neighboring rural areas. The 38 Members have experienced average annual compound growth rates from 2003 through 2005 of 3.0% in number of consumers, 5.5% in MWh sales and 10.6% in electric revenues.

The following table shows the aggregate peak demand and energy requirements of the Members for the years 2003 through 2005, and also shows the amounts of energy requirements supplied by Oglethorpe. From 2003 through 2005, demand and energy requirements of the Members increased at an average annual compound growth rate of 10.0% and 5.7%, respectively.


	Member Demand (MW)	Member Energy Requirements (MWh)
	Total ⁽¹⁾	Total ⁽²⁾	Supplied by Oglethorpe ⁽³⁾

2003	6,615	30,113,209	27,857,489
2004	7,238	32,201,281	29,799,921
2005	7,998	33,618,746	23,721,939

(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.

Service Area and Competition

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

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

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

Cooperative Structure

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

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

Rate Regulation of Members

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

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

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

Cobb EMC, Diverse Power Incorporated, an EMC, Mitchell EMC, Oconee EMC, Snapping Shoals EMC and Walton EMC have paid their RUS indebtedness and are no longer RUS borrowers. Each of these Members now has a rate covenant with its current lender. Other Members may also pursue this option. To the extent that a Member who is not an RUS borrower engages in wholesale sales or 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, interest rates are based on either Treasury rates or rates being paid on municipal bonds with comparable maturities. Certain borrowers with either low consumer density or higher-than-average rates and lower-than-average consumer income are eligible for special loans at 5%. Distribution borrowers are also eligible for loans made by FFB or other lenders and guaranteed by RUS. However, the availability and magnitude of RUS direct and guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, the availability of RUS loan funds is subject to increased uncertainty because of recent budgetary pressures faced by Congress. Oglethorpe cannot predict the amount or cost of RUS direct and guaranteed loans that may be available to the Members in the future.

Members' Relationships with GTC and GSOC

GTC provides transmission services to the Members for delivery of the Members' power purchases from Oglethorpe and other power suppliers. GTC and the Members have entered into Member Transmission Service Agreements (the "MTSAs") under which GTC provides transmission service to the Members pursuant to a transmission tariff. The MTSAs have a minimum term for network service 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 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 OPC and GTC, to provide to them the services that it purchases from GPC under the Control Area Compact, which Oglethorpe co-signed with GSOC. GSOC also provides operation services for the benefit of the Members through agreements with Oglethorpe, including dispatch of Oglethorpe's resources and other power supply resources owned by the Members.

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

Member Power Supply Resources

Oglethorpe Power Corporation

In 2005, Oglethorpe supplied energy sufficient to meet approximately 70% 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 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 2005, the aggregate SEPA allocation to the Members was 562 MW plus associated energy. Each Member must schedule its energy allocation, and each Member has designated Oglethorpe to perform this function. Pursuant to a separate agreement, Oglethorpe will schedule, through GSOC, the Members' SEPA power deliveries. Further, each Member may be required, if certain conditions are met, to contribute funds for capital improvements for Corps of Engineers projects from which its allocation is derived in order to retain the allocation.

Smarr EMC

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

GPC Block Purchase

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

Other Member Resources

Members are obtaining their other power supply requirements from various sources. Thirty Members have entered into contracts with third parties for all of their incremental power requirements, with remaining terms ranging from 5 to 12 years. The other Members use a portfolio of power purchase contracts to meet their requirements.

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

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

ENVIRONMENTAL AND OTHER REGULATION

General

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

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

Compliance with environmental standards will continue to be reflected in Oglethorpe's capital expenditures and operating costs. Oglethorpe made environmental-related capital expenditures of $3.5 million in 2005 and forecasts expenditures of approximately $47 million, $142 million and $137 million in 2006, 2007 and 2008, 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. One of the purposes of the Clean Air Act is to improve air quality. As a result, the reduction of emissions of sulfur dioxide, nitrogen oxides and mercury from affected electric utility units, which include the coal-fired units at Plants Wansley and Scherer, has been and may be required.

Sulfur dioxide reductions are being imposed through a sulfur dioxide emission allowance trading program. Through allowances issued by the U.S. Environmental Protection Agency ("EPA") pursuant to the Clean Air Act Amendments of 1990, aggregate emissions of sulfur dioxide from all affected units are now capped at 8.9 million tons per year. Emission allowances, each of which gives the holder the authority to emit one ton of sulfur dioxide during a particular calendar year or thereafter, are issued 30 years in advance and are transferable. Oglethorpe is 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 remains a possibility at Plant Scherer for compliance with these and future regulations to control sulfur dioxide, as discussed in more detail below.

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

A number of recently finalized regulations, proposed regulations and other actions could result in more stringent controls on all emissions, including utility emissions. The actions that appear to be the most significant are described below. However, with respect to emissions of sulfur dioxide and nitrogen oxides, additional controls at Plant Wansley are unlikely, but remain a possibility at Plant Scherer, as described below.

EPA has tightened the NAAQS for both ozone and fine particulate matter, an action that could affect any source that emits nitrogen oxides, sulfur dioxide or particulates, including utility units. The 1-hour ozone NAAQS was revoked for Georgia in 2005 and replaced with a new 8-hour ozone standard. New rules to implement the 8-hour standard, including area designations, have been issued, but are currently being challenged. The Atlanta ozone nonattainment area has been expanded from the original 13 counties (for the

1-hour NAAQS) to a 20-county area (for the 8-hour NAAQS). Macon, which has been separately designated as an 8-hour ozone nonattainment area, includes Plant Scherer within its boundaries. State implementation plans, including new emission control regulations necessary to bring those areas into attainment are generally due in 2007. Such plans may require further reductions of nitrogen oxides from Plant Scherer. Some or all of these reductions may come through implementation of the clean air interstate rulemaking discussed below. The impact of these new designations will depend on the development and implementation of any other applicable regulations as needed for attainment and cannot be determined at this time.

The final nonattainment area designations for the fine particulate matter NAAQS were issued in early 2005. Plants Wansley and Scherer were included in the designated areas. Later in 2005, EPA proposed a fine particulate matter implementation rule that it plans to adopt in 2006. State implementation plans to address such designations are due in 2008. Such plans could require reductions in sulfur dioxide and nitrogen oxide emissions, which are pre-cursors of fine particulate matter, from power plants, including Plant Scherer. The impact of these plans and associated regulations cannot be determined at this time. In addition, the possibility exists that the fine particulate matter NAAQS may be tightened even further in 2006, which could lead to more stringent controls for sulfur dioxide and nitrogen oxide emissions on power plants in the 2013 to 2020 time frame.

In 1998, EPA issued a regulation calling for regional reductions in nitrogen oxides emissions using fixed caps in 22 states, including Georgia. In April 2004, EPA finalized a new regional nitrogen oxides reduction rule for Georgia, which specified a May 2007 compliance deadline. EPA stayed the rule in 2005, however, as it initiated a rulemaking to reconsider the rule, granting a petition for reconsideration filed by a group of Georgia industries. Georgia's implementation plan for this regulation will depend on the disposition of the petition for reconsideration and any associated rulemaking. Therefore, it is not yet known what additional controls, if any, will be needed at Plant Scherer to comply with this regional nitrogen oxides reduction program. However, to achieve the reductions that may be necessary under these rules, the co-owners of Plant Scherer converted Scherer Units No. 1 and No. 2 from bituminous coal to sub-bituminous coal, substantially reducing the nitrogen oxides emissions from these units.

In March 2005, EPA finalized a clean air interstate rule for ozone and fine particulate matter that will require emissions reductions in sulfur dioxide and nitrogen oxides in most eastern states, including Georgia. The rule establishes a market-based cap and trade program, with emission caps for each affected state. Although the rule is final, it has been challenged. Moreover, Georgia is now considering how to include this rule in its state implementation plan. One possible result of the rule may be to require year-round reductions in emissions of sulfur dioxide and nitrogen oxides from power plants. Under the rule, the caps would be implemented in two phases. The first phase for nitrogen oxides caps would become effective in 2009 and for sulfur dioxide caps in 2010, each followed by a second phase in 2015. The rule may lead to the year-round operation of the selective catalytic reduction systems already installed at Plant Wansley and may require additional controls at Plant Scherer to comply with the state implementation plan now being developed to meet the established emission caps. The rule could also affect Georgia's upcoming plans for attaining the NAAQS for ozone and fine particulate matter discussed above, by providing regional emission reductions that would complement the required local reductions.

In 1999, EPA promulgated a new regional haze rule 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. State implementation plans to implement BART and reasonable further progress are due in December 2007. Until such rules are finalized and implemented by the State of Georgia, Oglethorpe will not know what controls, if any, may be required at Plant Scherer to comply with this rule.

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

In March 2005, EPA finalized a regulation that would control emissions of mercury, by creating a market-based cap-and-trade program that would reduce emissions of mercury in two phases, with the first phase becoming effective in 2010 and the second in 2018. Although announced as final, the rule has been challenged. Moreover, there is no guarantee that Georgia will allow a cap-and-trade program in its state implementation plan. Although controls installed to meet the requirements of the ozone and fine particulate NAAQs and the clean air interstate rule will produce some reductions in mercury emissions, the rule could require additional controls at Plants Wansley and/or Scherer in order to comply with the state implementation plan to be developed to meet the requirements of the rule for Georgia.

Because (1) several of these proposed or final Clean Air Act regulations could require control of the same emissions, (2) the compliance requirements are uncertain, and (3) specific control technologies affect multiple emissions, Oglethorpe cannot determine the aggregate effect of these or future regulations.

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

Domestic efforts to limit emissions of carbon dioxide from power plants are increasing. For example, Attorneys General from eight states and the Corporation Counsel of New York filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies in July 2004. The complaint alleges that the companies' emissions of carbon dioxide contribute to global warming, which the Plaintiffs claim is a public nuisance. Although not named in the complaint, Oglethorpe believes this claim is without merit. In September 2005, the Court granted the defendants' motions to dismiss, which the plaintiffs appealed in October 2005. While the outcome of this matter cannot be determined at this time, an adverse judgment could result in substantial capital expenditures at Plants Wansley and/or Scherer, which Oglethorpe co-owns with Georgia Power Company ("GPC"), a subsidiary of the Southern Company.

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

On November 3, 1999, the United States Justice Department, on behalf of EPA, filed lawsuits against GPC and some of its affiliates, as well as other utilities. The lawsuits allege violations of the new source review provisions and the new source performance standards of the Clean Air Act at, among other facilities, Scherer Unit Nos. 3 and 4. Oglethorpe is not currently named in the lawsuits and Oglethorpe does not have an ownership interest in the named units of Plant Scherer. However, Oglethorpe can give no assurance that units in which Oglethorpe has an ownership interest will not be affected by this or a related lawsuit in the future. The 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, the Sierra Club, Physicians for Social Responsibility, Georgia Forest Watch and one individual filed suit in Federal Court in Georgia against GPC alleging violations of the Clean Air Act at Plant Wansley. The complaint alleges violations of opacity limits at both the coal-fired units, in which Oglethorpe is a co-owner, and other violations at several gas-fired combined cycle units in which Oglethorpe does not have an ownership interest. This civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project and attorneys' fees. In December 2004, the U.S. District Court for the Northern District of Georgia issued an Order holding GPC liable for certain violations of the opacity limits at the coal-fired units. However, in March 2005 the U.S. Court of Appeals for the Eleventh Circuit allowed an immediate appeal of the Court's Order. In March 2006,

the Eleventh Circuit reversed the Order, remanding it back to the District Court for trial on the issues. While Oglethorpe believes that Plant Wansley has complied with applicable laws and regulations, resolution of this matter is uncertain at this time, as is any responsibility of Oglethorpe for a share of any penalties or other costs that might be assessed against GPC.

In January 2003, the Sierra Club appealed an unsuccessful challenge to an air operating permit for Chattahoochee to the 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 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 a subsequent order again denying the petition. In January 2006, the Sierra Club filed an appeal of that order to the U.S. Court of Appeals for the Eleventh Circuit. Although Oglethorpe believes that the appeal will not affect facility operations pending further consideration and that a favorable outcome in this matter is likely, an unfavorable ruling could temporarily affect the ability of the facility to continue operations.

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 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 stayed, but in March 2006 was vacated by the court. 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

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

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

Oglethorpe is subject to other environmental statutes including, but not limited to, the Georgia Water Quality Control Act, the Georgia Hazardous Site Response Act, the Toxic Substances Control Act, the Endangered Species Act, the Comprehensive Environmental Response, Compensation and Liability Act, the Emergency Planning and Community Right to Know Act, and to the regulations implementing these statutes. Oglethorpe does not believe that compliance with these statutes and regulations will have a material impact on its financial condition or results of operations. Changes to any of these laws, some of which are being reviewed by Congress, could affect many areas of Oglethorpe's operations. Although compliance with new environmental legislation could have a significant impact on Oglethorpe, those impacts cannot be fully determined at this time and would depend in part on

the final legislation and the development of implementing regulations.

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

Nuclear Regulation

Oglethorpe is subject to the provisions of the Atomic Energy Act of 1954, as amended (the "Atomic Energy Act"), which vests jurisdiction in the Nuclear Regulatory Commission ("NRC") over the construction and operation of nuclear reactors, particularly with regard to certain public health, safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the NRC to consider the environmental impact of a facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by the NRC. All aspects of the 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. The licenses for Plant Hatch were extended to their current expiration dates in January 2002. Under current regulations, Plant Vogtle will become eligible for an extension request in 2007.

Pursuant to the Nuclear Waste Policy Act of 1982, as amended, the federal government has the regulatory responsibility for the final disposition of commercially produced high-level radioactive waste materials, including spent nuclear fuel. This Act requires the owner of nuclear facilities to enter into disposal contracts with the Department of Energy ("DOE") for such material. These contracts require each such owner to pay a fee, which is currently one dollar per MWh for the net electricity generated and sold by each of its reactors.

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

Plants Hatch and Vogtle currently have on-site spent-fuel wet storage capacity and Plant Hatch has an on-site dry storage facility. The on-site dry storage facility for Plant Hatch became operational in 2000 and can be expanded to accommodate spent fuel through the life of the plant. Plant Vogtle's spent fuel pool storage is expected to be sufficient until 2015. Oglethorpe expects that procurement of on-site dry storage capacity at Plant Vogtle will commence in sufficient time to maintain full-core discharge capability to the spent fuel pool. (See Note 1 of Notes to Financial Statements.)

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

ITEM 1A. RISK FACTORS

The following describes the most significant risks, in management's view, that may affect Oglethorpe's business and financial condition. Additional risks and uncertainties, presently unknown to Oglethorpe or currently deemed not significant, could negatively impact Oglethorpe's results of operations or financial condition in the future.

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 and nitrogen oxides 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 will 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 can not 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 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 and operates 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% 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% 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 Nuclear Regulatory Commission;
•: potential liabilities arising out of the threat of a possible nuclear incident or terrorist attack; 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 Nuclear Regulatory Commission has broad authority under federal law to impose licensing and safety-related requirements for the operation of these facilities. If these facilities were found to be out of compliance with applicable requirements, the Nuclear Regulatory Commission may impose fines or shut down one or more units of these facilities until compliance is achieved. Revised safety requirements issued by the Nuclear Regulatory Commission have, in the past, necessitated substantial capital expenditures at other nuclear generating facilities. In addition, while 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 regarding exploration of development of up to two additional nuclear units at the Plant Vogtle site. Oglethorpe has an option to participate in up to 30% of any new project. While the extent of Oglethorpe's ultimate involvement, if any, will not be determined for two to four years, 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;
•: labor disputes or shortages;
•: 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.

Oglethorpe may incur significant costs related to ongoing capital expenditures at its generating facilities.

Oglethorpe's 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, which could have the effect of increasing the cost of electric service provided by Oglethorpe.

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 for construction of new generation facilities and as a significant source of liquidity for capital expenditures not satisfied by cash flow generated from operations. Historically, Oglethorpe and other electric cooperatives have relied principally on federal loan programs guaranteed by RUS and administered by FFB in order to meet a significant portion of their 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 were to decrease, Oglethorpe may have to seek alternative financing and its cost of borrowing could be adversely affected.

The capital markets have been at times subject to significant instability based on national and international events, including events in the energy industry and global acts of terrorism. Any such events could constrain, at least temporarily, Oglethorpe's liquidity and ability to access capital on favorable terms or at all. In addition, 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. Oglethorpe's credit ratings are currently investment grade, and management currently does not have any reason to expect a downgrade to below investment grade. However, Oglethorpe's credit ratings reflect the views of the rating agencies, which could change at any point in the future.

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 its members with wholesale electric power at the lowest possible cost. Other technologies currently exist or are in development, such as fuel cells, microturbines, windmills and solar cells, that may in the future be capable of producing electric power at costs that are comparable with, or lower than, 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 and natural gas. Oglethorpe has taken steps to manage this exposure by entering into fixed 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. Nevertheless, 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 Oglethorpe's 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

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
	Unit No. 2	Nuclear	30	348.0		1989	2029
Plant Wansley (near Carrollton, Ga.)
	Unit No. 1	Coal	30	259.5		1976	N/A	⁽¹⁾
	Unit No. 2	Coal	30	259.5		1978	N/A	⁽¹⁾
	Combustion Turbine	Oil	30	14.8		1980	N/A	⁽¹⁾
Plant Scherer (near Forsyth, Ga.)
	Unit No. 1	Coal	60	490.8		1982	N/A	⁽¹⁾
	Unit No. 2	Coal	60	490.8		1984	N/A	⁽¹⁾
Rocky Mountain (near Rome, Ga.)		Pumped Storage Hydro	74.61	632.5		1995	2027
Doyle (near Monroe, Ga.)		Gas	100	325.0	⁽²⁾	2000	N/A	⁽¹⁾
Talbot (near Columbus, Ga.)
	Units No. 1-4	Gas	100	412.0		2002	N/A	⁽¹⁾
	Units No. 5-6	Gas-Oil	100	206.0		2003	N/A	⁽¹⁾
Chattahoochee (near Carrollton, Ga.)		Gas	100	468.0		2003	N/A	⁽¹⁾

	Total			4,743.9

(1): 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.
(2): Nominal plant capacity identified in the Power Purchase and Sale Agreement with Doyle I, LLC. (See "The Plant Agreements –Doyle" below.)

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		2005		2004		2003		2005		2004		2003

Plant Hatch
	Unit No. 1	91	%	89	%	94	%	92	%	91	%	95	%
	Unit No. 2	86		97		91		87		96		91
Plant Vogtle
	Unit No. 1	90		99		91		91		100		93
	Unit No. 2	84		89		95		85		91		97
Plant Wansley
	Unit No. 1	89		99		87		78		81		79
	Unit No. 2	99		89		87		86		75		80
Plant Scherer ⁽³⁾
	Unit No. 1	97		86		72		88		76		58
	Unit No. 2	87		90		73		80		80		59
Rocky Mountain ⁽⁴⁾
	Unit No. 1	91		98		92		26		26		15
	Unit No. 2	97		90		99		10		8		20
	Unit No. 3	89		98		91		21		25		28
Doyle⁽⁴⁾⁽⁵⁾		98		100		100		2		0		0
Talbot ⁽⁴⁾		97		95		92		1		1		1
Chattahoochee		87		73		58		19		20		15

(1): Equivalent Availability is a measure of the percentage of time that a unit was available to generate if called upon, adjusted for periods when the unit is partially derated from the "maximum dependable capacity" rating.
(2): Capacity Factor is a measure of the output of a unit as a percentage of the maximum output, based on the "maximum dependable capacity" rating, over the period of measure.
(3): Plant Scherer's relatively low performance in 2003 was due to the outage time required for the conversion to use sub-bituminous coal, as described below.
(4): Rocky Mountain, Doyle and Talbot primarily operate as peaking plants, which results in low capacity factors.
(5): Equivalent Availability for each of Doyle's 5 units is measured only during the period May 15 – September 15, reflecting the contractual availability commitment of Doyle I, LLC. The units may be dispatched by Oglethorpe during other periods if the units are available.

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

Fuel Supply

Coal. Coal for Plant Wansley is currently purchased under term contracts and in spot market transactions, primarily from coal mines in the eastern United States. As of February 28, 2006, Oglethorpe had a 46-day coal supply at Plant Wansley based on continuous operation.

Coal for Scherer Units No. 1 and No. 2 is purchased under term contracts and in spot market transactions. As of February 28, 2006, Oglethorpe's coal stockpile at Plant Scherer contained a 14-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming. Oglethorpe's coal inventory at Plant Scherer is lower than normal due to rail transportation bottlenecks. Oglethorpe and the other co-owners are working with the rail transportation supplier to relieve the problem. Further, inventories are expected to recover somewhat while these units are out of service for routine spring maintenance. Failure to relieve the problem may require Oglethope to operate other generating plants at higher cost or require the Members to purchase energy from higher cost sources.

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

The Plant Scherer and Wansley ownership and operating agreements allow each co-owner (i) to dispatch separately its respective ownership interest in conjunction with contracting separately for long-term coal purchases procured by GPC and (ii) to procure separately long-term coal purchases. Oglethorpe separately dispatches Plant Scherer and Plant Wansley, but continues to use GPC as its agent for fuel procurement.

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

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

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

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, a registered holding company under the Public Utility Holding Company Act, and is engaged primarily in the generation and purchase of electric energy and the transmission, distribution and sale of such energy. GPC distributes and sells energy within the State of Georgia at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome and Valdosta), as well as in rural areas, and at wholesale to Oglethorpe, MEAG and two municipalities. GPC is the largest supplier of electric energy in the State of Georgia. (See "BUSINESS – OGLETHORPE POWER CORPORATION – Relationship with GPC.") GPC is subject to the informational requirements of the Securities Exchange Act of 1934, as amended, and, in accordance therewith, files reports and other information with the Commission.

Municipal Electric Authority of Georgia

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

City of Dalton, Georgia

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

The Plant Agreements

Hatch, Wansley, Vogtle and Scherer

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

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

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

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

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

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

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

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

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

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

In conjunction with the potential development of additional units at Plant Vogtle (see "OGLETHORPE'S POWER SUPPLY RESOURCES – Future Power Resources" in Item 1), the co-owners have negotiated amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, which will be subject to RUS approval.

Rocky Mountain

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

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

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

In late 1996 and early 1997, Oglethorpe completed lease transactions for its 74.61% undivided ownership interest in Rocky Mountain. 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."

Doyle

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

During the term of the agreement, Oglethorpe has the right and obligation to purchase all of the capacity and

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

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

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

ITEM 3. LEGAL PROCEEDINGS

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

For information about environmental matters that could have an effect on Oglethorpe, see Note 12 of Notes to Financial Statements.

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

Not applicable.

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PART II

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

Not Applicable.

ITEM 6. SELECTED FINANCIAL DATA (UNAUDITED)

The following table presents selected historical financial data of Oglethorpe. The financial data presented as of the end of and for each year in the five-year period ended December 31, 2005, have been derived from the audited financial statements of Oglethorpe. This data should be read in conjunction with the financial statements of Oglethorpe and the notes thereto included in Item 8 and "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS" in Item 7.

				(dollars in thousands)
				2005			2004			2003			2002			2001

Operating revenues:
	Sales to Members		$	1,136,463		$	1,279,465		$	1,167,605		$	1,127,519		$	1,080,478
	Sales to non-Members			33,060			33,307			35,948			35,802			58,811

Total operating revenues				1,169,523			1,312,772			1,203,553			1,163,321			1,139,289

Operating expenses:
	Fuel			365,073			290,106			234,172			225,008			221,449
	Production			251,830			248,084			253,865			232,312			218,480
	Purchased power			255,616			402,941			359,447			357,491			414,382
	Depreciation and amortization			153,030			153,126			141,301			140,058			133,731
	Accretion			33,996			20,456			7,815			–			–
	Income taxes			–			(3	)		(459	)		–			(63,485	)
	Gain on sale of emission allowances			(83,098	)		–			–			–			–

Total operating expenses				976,447			1,114,710			996,141			954,869			924,557

Operating margin				193,076			198,062			207,412			208,452			214,732
Other income, net				45,123			42,228			32,737			35,911			51,345
Net interest charges				(220,546	)		(223,053	)		(223,300	)		(226,823	)		(247,660	)

Net margin			$	17,653		$	17,237		$	16,849		$	17,540		$	18,417

Electric plant, net:
	In service		$	3,427,101		$	3,547,337		$	3,665,991		$	3,084,772		$	3,147,274
	Nuclear fuel, at amortized cost			94,159			87,941			90,283			77,247			77,360
	Construction work in progress			26,721			22,830			26,212			69,282			38,564

Total electric plant			$	3,547,981		$	3,658,108		$	3,782,486		$	3,231,301		$	3,263,198

Total assets			$	4,828,075		$	4,813,178		$	4,947,397		$	4,556,940		$	4,712,831

Capitalization:
	Long-term debt		$	3,238,648		$	3,351,664		$	3,534,185		$	2,959,194		$	3,041,287
	Obligations under capital leases			332,434			344,412			360,697			375,720			389,487
	Obligation under Rocky Mountain transactions			88,689			83,012			77,684			72,698			68,032
	Patronage capital and membership fees			479,308			461,655			444,418			427,569			410,029
	Accumulated other comprehensive loss			(34,339	)		(46,896	)		(49,814	)		(55,751	)		(42,361	)

	Subtotal			4,104,740			4,193,847			4,367,170			3,779,430			3,866,474
		Less: long-term debt and capital leases due within one year		(217,743	)		(190,835	)		(237,522	)		(140,241	)		(127,621	)

Total capitalization			$	3,886,997		$	4,003,012		$	4,129,648		$	3,639,189		$	3,738,853

Property additions			$	75,065		$	65,798		$	171,126		$	105,824		$	69,824

Energy supply (megawatt-hours):
	Generated			20,962,600			21,035,609			18,956,147			18,969,282			19,157,910
	Purchased			3,812,809			11,167,140			10,888,883			10,845,701			11,448,219

	Available for sale			24,775,409			32,202,749			29,845,030			29,814,983			30,606,129

Member revenues per kWh sold				4.79¢			4.10¢			4.00¢			4.04¢			4.01¢

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

Forward-Looking Statements and Associated Risks

This Annual Report on Form 10-K contains forward-looking statements, including statements regarding, among other items, (i) anticipated trends in the business of Oglethorpe, (ii) Oglethorpe's future power supply requirements, resources and arrangements, (iii) Oglethorpe's expected future capital expenditures and (iv) disclosures regarding market risk included in "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK." Some forward-looking statements can be identified by use of terms such as "may," "will," "expects," "anticipates," "believes," "intends," "projects," "plans" or similar terms. These forward-looking statements are based largely on Oglethorpe's current expectations and are subject to a number of risks and uncertainties, some of which are beyond Oglethorpe's control. For some of the factors that could cause actual results to differ materially from those anticipated by these forward-looking statements, see "ACCOUNTING POLICIES –Critical Accounting Policies" below, "BUSINESS – OGLETHORPE POWER CORPORATION – Competition" and "ENVIRONMENTAL AND OTHER REGULATION." In light of these risks and uncertainties, Oglethorpe can give no assurance that events anticipated by the forward-looking statements contained in this Annual Report will in fact transpire.

Executive Overview

Oglethorpe is a not-for-profit electric cooperative whose principal business is providing wholesale electric service to 38 Members. Consequently, substantially all of Oglethorpe's revenues and cash flow is derived from sales to the Members pursuant to long-term, take-or-pay wholesale power contracts. These contracts obligate the Members jointly and severally to pay all of Oglethorpe's costs and expenses associated with owning and operating its power supply business. To that end, Oglethorpe's existing rate structure provides for a pass-through of actual energy costs. Charges for fixed costs (including capacity, other non-energy charges, debt service obligations and the margin required to meet Oglethorpe's Margins for Interest Ratio rate covenant) are carefully managed throughout the year to ensure that sufficient capacity-related revenues are produced. This rate structure provides Oglethorpe with the ability to manage its revenues to assure full recovery of its costs in rates and has resulted in a consistent record of meeting all of its financial requirements. The year 2005 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.

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 expects to refinance or otherwise reamortize a portion of its long-term debt to better match the amortization of its debt to the projected useful lives of its assets.

In 2005, 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 $580 million.

In 2003, Oglethorpe entered into 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 at the end of December 2004 and March 2005, respectively. While Oglethorpe resources (generating facilities and power purchase contracts) had historically provided more than 90% of the Members' requirements, since the terminations of the power marketer agreement with LG&E Energy Marketing Inc. ("LEM") at the end of 2004 and the power marketer agreement with Morgan Stanley Capital Group Inc. ("Morgan Stanley") at the end of March 2005, Oglethorpe resources have been providing only approximately 70% of the Members' requirements. Plans by the Members to replace the portion of energy being provided by these two agreements were implemented smoothly.

The absence of these two agreements from Oglethorpe's power supply portfolio resulted in an increase to the average cost of power that is supplied by Oglethorpe to the Members. There are two reasons for this. First, the energy that was provided pursuant to these two agreements was at a very favorable cost to Oglethorpe. But, more importantly, because Oglethorpe is selling approximately 26% less energy to its Members, spreading Oglethorpe's fixed costs (which remain relatively unchanged) over fewer MWhs sold has the effect of increasing Oglethorpe's average cost of power. Oglethorpe's average power cost in 2005 actually increased by approximately 17% over 2004. This increase would have been greater; however, Oglethorpe's sale of excess SO₂ allowances in 2005 helped mitigate this increase.

When SO₂ allowance prices spiked to new highs in 2005, Oglethorpe implemented a systematic program of selling some of its excess allowances. Sales in 2005 netted approximately $83 million of which $62 million was used to offset Oglethorpe's cost of power to its Members. Oglethorpe continued this program into the first quarter of 2006, producing an additional $38 million of sales proceeds. All of these proceeds will be used to reduce Oglethorpe's cost of power to its Members, either in 2006 or in subsequent years. Oglethorpe will continue to monitor the market for SO₂ allowances and its own allowance requirements and may sell additional allowances in the future.

From time to time, Oglethorpe may assist the Members in investigating potential new power supply resources. Oglethorpe and the Members are 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 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% of any new project. Although preliminary decisions may be made over the next two years, the extent of Oglethorpe's ultimate involvement, if any, will not be determined for two to four years.

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

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

Additionally, there are certain risks inherent in Oglethorpe's undivided ownership interests in its two nuclear facilities, Plants Hatch and Vogtle. One such risk is the storage of spent fuel. While the progress towards a national repository is disappointing, both 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 the funding for the expected cost of decommissioning. Oglethorpe continues to maintain appropriate balances in its external trust fund based on recent specific site studies, NRC minimum funding requirements and assumptions regarding investment earnings. With respect to

operational risk, both plants continue an excellent record of operations with availability and capacity factors exceeding 84% in 2005.

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

Summary of Cooperative Operations

Margins and Patronage Capital

Oglethorpe operates on a not-for-profit basis and, accordingly, seeks only to generate revenues sufficient to recover its cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. Revenues in excess of current period costs in any year are designated as net margin in Oglethorpe's statements of revenues and expenses and patronage capital. Retained net margins are designated on Oglethorpe's balance sheets as patronage capital, which is allocated to each of the Members on the basis of its electricity purchases from Oglethorpe. Since its formation in 1974, Oglethorpe has generated a positive net margin in each year and had a balance of $479 million in patronage capital as of December 31, 2005. Oglethorpe's equity ratio, calculated as patronage capital and membership fees divided by total capitalization, increased from 11.5% at December 31, 2004 to 12.3% at December 31, 2005.

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

Rates and Regulation

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

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

Under the Mortgage Indenture, Oglethorpe is required, subject to any necessary regulatory approval, 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 2005, 2004 and 2003, Oglethorpe achieved a Margins for Interest Ratio of 1.10.

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

Accounting Policies

Basis of Accounting

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

Critical Accounting 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 require assumptions about matters that were uncertain at the time of preparation of Oglethorpe's financial statements. Oglethorpe's management has discussed the development, selection and disclosure of critical accounting policies and estimates with the Audit Committee of Oglethorpe's Board of Directors.

Regulatory Assets and Liabilities

Oglethorpe is subject to the provisions of Statement of Financial Accounting Standards ("SFAS") No. 71, "Accounting for the Effects of Certain Types of Regulation." SFAS No. 71 permits Oglethorpe to record regulatory assets and regulatory liabilities to reflect future cost recovery or refunds that Oglethorpe has a right to pass through to the Members. At December 31, 2005, Oglethorpe's regulatory assets and liabilities totaled $252 million and $124 million, respectively. (See Note 1 of Notes to Financial Statements.) While Oglethorpe does not currently foresee any event such as competitive or other factors that would make it not probable that Oglethorpe will recover these costs from its Members as future revenues through rates under its Wholesale Power Contracts, if such an event were to occurr, 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 March 2005, the Financial Accounting Standards Board (FASB) issued Interpretation No. 47, "Accounting for Conditional Asset Retirement Obligations" ("Interpretation No. 47"). This Interpretation clarifies that the term "conditional asset retirement obligation" as used in Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations", refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of Oglethorpe. The obligation to perform the asset retirement activity is unconditional even though uncertainty may exist about the timing and/or method of settlement. Thus, the timing and/or method or settlement may be conditional on a future event. Accordingly, Oglethorpe is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. At December 31, 2005, Oglethorpe recorded additional asset retirement obligations of $3.0 million for asbestos removal with an offsetting increase to regulatory assets. The adoption of Interpretation No. 47 did not have any effect on net margin. For further discussion see "Asset retirement obligations" in Note 1 of Notes to Financial Statements.

In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments",

an amendment of FASB Statements No. 133 and 140. This statement resolves issues addressed in SFAS No. 133 Implementation Issue No. D41, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 is effective for fiscal years beginning after September 15, 2006. Oglethorpe will implement this standard effective January 1, 2007. Oglethorpe does not expect this statement to have an impact on its financial statements.

Proposed Accounting Interpretation

In July 2005, the FASB issued an Exposure Draft of a proposed Interpretation, "Accounting for Uncertain Tax Positions-an Interpretation of FASB Statement No. 109." The objective of the Proposed Interpretation is to clarify the accounting for uncertain tax positions. Generally, an entity would be required to recognize, in its financial statements, the best estimate of the impact of a tax position only if that position is more likely than not of being sustained on audit based solely on the technical merits of the position. The tax position should be derecognized when it is no longer more likely than not of being sustained. Oglethorpe is monitoring developments of the Proposed Interpretation and is assessing the impact that the Proposed Interpretation may have on its financial statements. Oglethorpe cannot predict what actions the FASB will take or how such actions might ultimately affect Oglethorpe's financial position or results of operations.

Results of Operations

Power Marketer Arrangements

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

The absence of these two agreements from Oglethorpe's power supply portfolio resulted in an increase to the average cost of power supplied by Oglethorpe to the Members. There are two reasons for this. First, the energy that was provided pursuant to these two agreements was at a very favorable cost to Oglethorpe. But, more importantly, because the termination of these agreements resulted in Oglethorpe selling 24% less energy to its Members, the spreading of Oglethorpe's fixed costs (which remain relatively unchanged) over fewer MWhs sold had the effect of increasing Oglethorpe's average cost of power. For further discussion regarding purchased power costs see "Operating Expenses" below.

In October 2004, LEM and its affiliates initiated a binding arbitration process to resolve certain issues relating to the LEM agreement. Oglethorpe recorded a $15 million reserve at December 31, 2004 for estimated damages payable to LEM. In June 2005, the arbitration panel selected LEM's remedy, which required Oglethorpe to pay LEM approximately $16 million. Oglethorpe recorded an additional $1.0 million of purchased power energy costs during the second quarter of 2005 and payment was made to LEM in July 2005. The $16.0 million accrual previously reflected as an unbilled receivable on the balance sheet was billed to the Members in July 2005.

Operating Revenues

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

Total revenues from sales to Members decreased by 11.2% for 2005 compared to 2004 and increased by

9.6% for 2004 compared to 2003. The components of Member revenues were as follows:


		(dollars in thousands)
		2005		2004		2003

Capacity revenues	$	552,264	$	626,324	$	609,826
Energy revenues		584,199		653,141		557,779

Total	$	1,136,463	$	1,279,465	$	1,167,605

Capacity revenues from Members decreased 11.8% in 2005 compared to 2004 and increased by 2.7% from 2003 to 2004. For 2005 compared to 2004, the decrease in capacity revenues resulted primarily from the Board of Directors approved reduction to revenue requirements ($61.9 million) to offset a portion of the proceeds received from sale of SO₂ allowances. See Note 10 of Notes to Financial Statements for further discussion regarding the sale of SO₂ allowances. In addition, capacity revenues were reduced due to the Members' monthly power bill prepayment program that provides the Members with a discount for prepaying their monthly power bills. The prepayment funds are deposited in the RUS Cushion of Credit Account. See "Liquidity and Sources of Capital" for further discussion of the Members prepayment program and the RUS Cushion of Credit Account. The increase in capacity revenues in 2004 and 2003 was primarily due to an increase in revenue requirement beginning in May 2003 associated with fixed cost recovery for the Chattahoochee and Talbot generating facilities acquired by Oglethorpe in May 2003.

Energy revenues from Members decreased by 10.6% in 2005 compared to 2004 and increased by 17.1% in 2004 compared to 2003. The decrease in energy revenues for 2005 was primarily due to a decrease in the pass-through of purchased power energy costs due to the expiration of power marketer agreements with LEM and Morgan Stanley. See "Power Marketers Arrangements" above for further discussion. Lower purchase power energy costs were offset somewhat by higher energy costs associated with significantly higher natural gas prices incurred for fuel used at Oglethorpe's combustion turbine facilities and to higher generation and fuel costs at Oglethorpe's coal-fired generating plants. The increase in Member energy revenues in 2004 as compared to 2003 resulted partly from recovery of increases in fuel costs for the Chattahoochee, Talbot and Plant Scherer generating facilities and partly due to increases in purchased power energy costs. (See "Operating Expenses" below.)

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


	Kilowatt-hours	Cents per Kilowatt-hour

2005	23,721,939	4.79
2004	31,213,210	4.10
2003	29,193,998	4.00

In 2005 kWh sales to Members decreased 24.0% and in 2004 kWh sales to Members increased 6.9%. The average revenue per kWh from sales to Members increased 16.9% for 2005 compared to 2004 and increased 2.5% for 2004 compared to 2003. The decrease in kWh sales to Members in 2005 resulted from the termination of the LEM and Morgan Stanley power marketer agreements as previously dicussed.

The energy portion of Member revenues per kWh increased 17.7% in 2005 as compared to 2004 and increased 9.5% in 2004 compared to 2003. Oglethorpe passes through actual energy costs to the Members such that energy revenues equal energy costs. The higher energy revenues per kWh in 2005 resulted primarily from the termination of the LEM and Morgan Stanley power marketer agreements. The increase in 2004 of energy revenues per kWh was partly due to the pass-through of higher purchased power costs and partly due to the recovery of increases in fuel costs. (See "Operating Expenses" below.)

Sales to Non-Members. Sales to non-Members were primarily from capacity and energy sales to Alabama Electric Cooperative under an agreement to sell 10 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 2005, 2004 and 2003 were $33,060,000, $33,307,000 and $35,948,000, respectively.

Operating Expenses

Oglethorpe's operating expenses, excluding the 2005 income related to the sale of SO₂ allowances of $83.1 million, were 4.9% lower in 2005 compared to 2004 and 11.9% higher in 2004 compared to 2003. The decrease in operating expenses for 2005 was primarily due to lower purchased power costs offset somewhat by

higher fuel and accretion expenses. Operating expenses were higher in 2004 compared to 2003 primarily as a result of increases to fuel costs, purchased power costs, depreciation and amortization expense and accretion expense offset slightly by lower production expenses.

Total fuel costs increased 25.8% in 2005 as compared to 2004 and increased 23.9% in 2004 as compared to 2003. The increase in total fuel costs in 2005 resulted from both the mix of generation and the higher prices incurred for natural gas. The higher percentage of generation from fossil and gas-fired facilities combined with the higher natural gas prices for 2005 as compared to 2004 resulted in a 26.1% increase in average fuel costs. For 2005 compared to 2004 total generation decreased less then 1%. For 2004 as compared to 2003 the increase in total fuel costs was partly as a result of an increase in MWhs of generation (primarily due to increased MWhs sold to Members) of 9.8% and partly due to higher average fuel costs associated with increased fossil generation and generation output from the Chattahoochee facility, a gas-fired combined cycle plant, acquired in May 2003. For 2004 compared to 2003, output from the coal-fired facilities was 18.7% higher and generation from the Chattahoochee facility was 281,000 MWhs higher.

Production expenses increased slightly for 2005 compared to 2004 and decreased 2.2% in 2004 compared to 2003 For 2004, production expenses decreased partly due to the reversal of a $1.7 million reserve recorded in 2003 for property taxes related to Plant Vogtle and partly due to $3 million of start-up costs incurred in 2003 related to the Chattahoochee and Talbot generating facilites. There were no such start-up costs incurred in 2004. See Note 13 of Notes to Financial Statements for further discussion regarding ad valorem tax matters.

Purchased power costs decreased 36.6% in 2005 compared to 2004 and increased 12.1% in 2004 compared to 2003 as follows:


		(dollars in thousands)
		2005		2004		2003

Capacity costs	$	60,683	$	63,304	$	62,280
Energy costs		194,933		339,637		297,167

Total	$	255,616	$	402,941	$	359,447

The decrease in purchased power capacity costs for 2005 as compared to 2004 resulted primarily from a decrease in the cost of services provided by Georgia System Operations Corporation (GSOC).

Purchased power energy costs decreased 42.6% in 2005 compared to 2004 and increased 14.3% in 2004 compared to 2003. The average cost of purchased power energy per kWh increased 68.1% in 2005 compared to 2004 and increased 11.4% in 2004 compared to 2003. The decrease in purchased power energy costs in 2005 resulted primarily from the termination of the LEM and Morgan Stanley power marketer agreements offset somewhat by an increase in energy purchases from other power companies. The increase in average purchased power energy costs in 2005 was a result of the termination of the LEM and Morgan Stanley agreements which provided energy at very favorable costs. The increase in 2004 as compared to 2003 for average purchased power costs resulted from (1) a $15 million accrual as a contingent liability to LEM, (2) slightly higher prices both in the wholesale electricity markets and for energy purchases made from purchased power agreements and (3) an increased amount of purchased power MWhs. The amount of purchased power MWhs decreased 65.9% in 2005 compared to 2004 and increased 2.6% in 2004 compared to 2003.

Purchased power expenses for the years 2003 through 2005 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 $126 million in 2005, $92 million in 2004 and $79 million in 2003. For a discussion of the power purchase agreements, see Note 9 of Notes to Financial Statements.

Depreciation and amortization remained flat from 2004 to 2005 and increased 8.4% in 2004 compared to 2003. The higher depreciation and amortization expense in 2004 was primarily due to depreciation expense associated with the Chattahoochee and Talbot generating facilities acquired by Oglethorpe in May 2003. In addition, higher amortization associated with leasehold improvements at Scherer Unit No. 2 contributed to the increase.

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

the expense recovered for ratemaking purposes. Accretion expense increased from $20.5 million in 2004 to $34.0 million in 2005. Note that the higher accretion expense is primarily due to the increased amortization of deferred asset retirement costs. The accretion expense recognized is equal to the earnings from the decommissioning trust fund. In addition, as discussed in Note 10 of Notes to Financial Statements, in 2005 $21.2 million of net proceeds from sale of SO₂ allowances was offset with a like amount of amortization of deferred asset retirement costs. The $21.2 million of net proceeds were retained in the internal decommissioning fund. In 2004 Oglethorpe recovered more accretion expense in its rates compared to the amount of accretion expense recovered in rates for 2003 due to higher earnings from the decommissioning trust fund in 2004 as compared to 2003. For a discussion regarding adoption of SFAS No. 143, see Note 1 of Notes to Financial Statements.

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. As previously discussed, 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 amortization of deferred asset retirement costs in the form of accretion expense. As a result there was no net change to margin.

Other Income (Expense)

Investment income increased 8.3% in 2005 compared to 2004 and increased 44.2% in 2004 compared to 2003. The increase in 2005 compared to 2004 was primarily due to earnings on funds deposited in the RUS Cushion of Credit account offset somewhat by lower earnings from the decommissioning trust fund. The increase in 2004 as compared to 2003 was primarily due to higher earnings from the decommissioning trust fund.

Interest Charges

Other interest expense increased slightly for 2005 as compared to 2004 and decreased 47.9% or $2.6 million in 2004 compared to 2003. The lower other interest expense in 2004 and 2003 was primarily attributable to commercial paper issued to finance a portion of the Talbot EMC and Chattahoochee EMC construction projects being refinanced with long-term FFB loans and the related interest costs are now reflected in interest on long-term debt and capital leases. Amortization of debt discount and expense increased 15.1% in 2004 compared to 2003 primarily due to amortization of debt issuance costs associated with a $133.3 million PCB refunding transaction completed in December 2003.

Net Margin

Oglethorpe's net margin for 2005, 2004 and 2003 was $17.7 million, $17.2 million and $16.8 million, respectively. These amounts were 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 were $1.4 million, $1.3 million and $1.0 million for 2005, 2004 and 2003, respectively. (See "Summary of Cooperative Operations –Rates and Regulations" above.)

Financial Condition

Overview

In 2005, Oglethorpe repaid $150 million of long-term debt and capital leases and issued $25 million in new long-term debt. The new debt issuance included draws totaling $9 million under FFB loans for the Talbot and Chattahoochee Energy Facilities, and $16 million in tax-exempt bond proceeds relating to a refinancing of PCB debt that matured in January 2006. Oglethorpe had no short-term debt outstanding at December 31, 2005.

The average interest rate on long-term debt and capital lease obligations was 5.4% at December 31, 2005.

Oglethorpe's 2005 net margin of $18 million caused a corresponding increase in patronage capital (equity), bringing total patronage capital to $479 million at December 31, 2005. Oglethorpe's equity to capitalization ratio was 12.3% at year end.

Oglethorpe maintained a strong liquidity position with $580 million of unrestricted available liquidity at December 31, 2005. This amount included $171 million of cash and cash equivalents, $9 million of investments and $400 million of committed credit arrangments. The committed credit arrangements were fully available at year end.

Restricted short-term investments were $222 million at December 31, 2005, an increase of $141 million over year-end 2004. The increase was due to additional funds being deposited into the RUS Cushion of Credit Account.

See "Liquidity and Sources of Capital" below for additional information on Oglethorpe's liquidity position and the RUS Cushion of Credit Account.

Property additions totaled $75 million and were financed with funds from operations. The expenditures were primarily for purchases of nuclear fuel ($40 million) and additions and replacements to existing generation facilities ($33 million).

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

Liquidity and Sources of Capital

Sources of Capital. Oglethorpe has historically obtained the majority of its long-term financing from RUS-guaranteed loans funded by FFB. In the future, however, RUS-guaranteed funding for new generation facilities may be limited due to budgetary pressures faced by Congress. In addition, over the next ten years G&T loan demand is projected to exceed RUS-guaranteed funding authorization levels unless there is an increase over current levels of funding. Therefore, any new generation facilities that Oglethorpe may build in the future on behalf of its Members may be financed through a variety of sources, including RUS-guaranteed loans and capital market financings.

Oglethorpe has also obtained a substantial portion of its long-term financing requirements from the issuance of tax-exempt PCBs and expects that it will be able to issue additional tax-exempt debt in the future. However, the types of equipment that will qualify for tax-exempt financing is less than in the past due to changes in tax laws.

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 generation facilities, expenditures relating to environmental compliance at generation facilities, general plant additions, and retirement of long-term debt. In the future, Oglethorpe anticipates that it will meet these types of capital requirements through a combination of funds generated from operations and short and long-term borrowings.

See "Financing Activities" below for additional information regarding Oglethorpe's financing plans.

Liquidity. At December 31, 2005, Oglethorpe had $580 million of unrestricted available liquidity to meet short-term cash needs and liquidity requirements. This liquidity consisted of (i) $171 million in cash and cash equivalents, (ii) $9 million in other investments, and (iii) up to $400 million available under the following committed line of credit ("LOC") facilities:


Committed Short-Term Credit Facilities
(dollars in millions)
			Authorized Amount		Available Amount	Expiration Date

Commercial Paper
	Backup Line of Credit	$	300	$	300	September 2007
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.

Oglethorpe periodically assesses its needs to determine the appropriate amount of commercial paper backup to maintain and currently has in place a $300 million committed backup facility provided by a group of six banks that was syndicated by Bank of America. The facility includes an accordion provision that provides a mechanism to increase the size of the revolving loan commitment up to $370 million, pending bank approval of the increase at the time of the request.

The commercial paper backup line of credit contains a financial covenant requiring Oglethorpe to maintain patronage capital at levels not less than 110% of the facility commitment amount. This currently equates to $330 million, and year-end patronage capital exceeded this amount by $149 million. One additional covenant limits secured indebtedness to $4.5 billion and unsecured indebtedness to $1 billion during the term of the credit agreement.

Along with the CoBank and CFC lines of credit, the backup facility supporting commercial paper may also be used for general working capital needs. Under the commercial paper program Oglethorpe is authorized to

issue commercial paper in amounts that do not exceed the amount of its committed backup line of credit, thereby providing 100% dedicated support for any paper outstanding. Therefore, if any amounts are drawn under the backup facility for working capital, it will reduce the amount of commercial paper that Oglethorpe can issue.

In addition to unrestricted available liquidty, Oglethorpe had $238 million in restricted cash and cash equivalents and restricted short-term investments at December 31, 2005. Of this amount, $16 million was on deposit with a trustee relating to PCBs issued in November 2005, the proceeds of which were used to refinance a like amount of PCB principal maturing in January 2006. (See "Financing Activities" below.) The remaining $222 million relates to a RUS Cushion of Credit Account established on a voluntary basis with the U.S. Treasury in mid-2004 that earns interest at a guaranteed rate of 5% per annum. The funds in the account, including interest earned thereon, can only be applied to future debt service on RUS and RUS-guaranteed FFB notes. In 2004, Oglethorpe deposited $80 million into the Cushion of Credit Account, and by December 31, 2005 this amount had grown to $86 million.

In 2005, Oglethorpe made additional deposits into the Cushion of Credit Account in connection with a program that was implemented under which the Members can prepay, at a discount, their monthly power bill from Oglethorpe. This program has been continued through 2006. Although restricted, the funds in the Cushion of Credit Account provide a source of short-term liquidity as funds on deposit are being applied to quarterly RUS and FFB debt service obligations.

Liquidity Covenants. Oglethorpe currently has three financial agreements in place which contain liquidity covenants. These agreements include the two interest rate swaps relating to PCB transactions and the Rocky Mountain lease transactions. The amount of liquidity required under these agreements was $72 million as of December 31, 2005, and Oglethorpe had sufficient liquidity to satisfy these requirements.

Financing Activities

In August 2005, RUS approved a $92 million loan for Oglethorpe that will fund routine additions and replacements to generation facilities incurred in 2004 and 2005, and those expected to be incurred in 2006 through 2007. Oglethorpe expects to begin drawing down this loan in May 2006 and to have it fully drawn by 2011. This loan will be funded through the FFB and guaranteed by the RUS, and the debt will be secured under Oglethorpe's Mortgage Indenture.

In September 2005, Oglethorpe submitted a loan application to the RUS for up to $210 million to fund capital expenditures forecasted to be made in complying with environmental regulations. Oglethorpe does not expect RUS to act on this loan request until 2007. If approved, this loan would be funded through the FFB and guaranteed by the RUS, and the debt would be secured under Oglethorpe's Mortgage Indenture.

Oglethorpe plans to issue approximately $50 million of tax-exempt bonds relating to the qualifying portion of scrubbers currently being installed at coal-fired Plant Wansley. Oglethorpe received the required state allocation for this tax-exempt financing in 2005, and the bonds can be issued any time within a three-year window that expires at year-end 2008.

Oglethorpe has a program in place under which it is refinancing, on a continued tax-exempt basis, the annual principal maturities of serial bonds and the annual sinking fund payments of term bonds originally issued on behalf of Oglethorpe by various county development authorities. The refinancing of these PCB principal maturities allows Oglethorpe to preserve a low-cost source of financing. To date, Oglethorpe has refinanced approximately $225 million under this program, including $16 million of PCB principal that matured in January 2006. Oglethorpe plans to refinance an additional $21 million of PCB principal that matures in January 2007, and anticipates seeking Board approval to continue this refinancing program for the foreseeable future.

Under an indemnity agreement executed in connection with GTC's assumption of PCB indebtedness in the 1997 corporate restructuring (see "Off-Balance Sheet Arrangements – GTC Debt Assumption" below), GTC is entitled to participate in any prepayment of assumed PCB debt by agreeing to assume a portion of the refunding debt. Since 1999, GTC has not participated in the annual refinancings of PCB principal at maturity. Under a separate agreement between the companies, Oglethorpe is providing a discount to GTC of 30% relating to their share of the annual maturity refinancings. As such, in connection

with the $16 million PCB refinancing discussed above, Oglethorpe provided a discount of $0.8 million and received cash of $1.9 million on the $2.7 million due from GTC. Oglethorpe and GTC are currently evaluating options that would allow GTC to participate in the annual maturity refinancings, possibly beginning with the $21 million PCB refinancing planned for later in 2006.

In connection with the extension of the wholesale power contracts from 2025 to 2050, Oglethorpe is evaluating various options to extend the maturities of a portion of its FFB and PCB debt. An extension of the maturitites will provide 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. In particular, Oglethorpe is considering a transaction that would combine one or more of its PCB bullet maturities (currently due in the 2018 to 2024 time frame) with PCB amortizing principal due in January 2007 in a refinancing that would close in 2006.

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 2006 through 2008. Actual expenditures may vary from the estimates listed below because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, cost of capital, equipment, material and labor, and changing environmental requirements.


Capital Expenditures ⁽¹⁾
(dollars in thousands)
	Year		Existing Generation		Environmental Compliance		Nuclear Fuel		General Plant		Total

	2006	$	40,800	$	47,400	$	58,800	$	2,000	$	149,000
	2007		49,000		141,500		41,000		3,000		234,500
	2008		40,200		136,800		44,400		2,700		224,100

	Total	$	130,000	$	325,700	$	144,200	$	7,700	$	607,600

(1): Excludes allowance for funds used during construction.

In addition to the expenditures reflected in the table above, $24 million is projected to be paid to GPC through October 2007 relating to the nuclear development option agreement. Pursuant to this agreement, these costs are fully refundable if the Members decide not to participate in the new nuclear units. For a more detailed discussion of this agreement, see "OGLETHORPE'S POWER SUPPLY RESOURCES – Future Power Resources" in Item 1 herein.

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 to be debated on a national level, it is difficult to predict what capital costs may ultimately be required, even in the near term. Oglethorpe monitors the on-going debate to gauge a range of possible capital expenditure outcomes. The environmental compliance expenditures reflected in the table above include a scrubber installation project (for sulfur dioxide removal) currently underway at Plant Wansley and contemplated environmental compliance projects that may begin at Plant Scherer in the near term. While estimates can vary widely, it is not unlikely that Oglethorpe may be required to make additional investments in the range of approximately $400 million to $600 million relating to environmental compliance programs beyond the period reflected in the table above.

Depending on how Oglethorpe and the other co-owners of Plants Scherer and Wansley choose to comply with these regulations, once finalized, both capital expenditures and operating expenditures may be impacted. 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, 2005, Oglethorpe's contractual obligations for the periods indicated.


Contractual Obligations
(dollars in thousands)
As of 12/31/05			2006		2007- 2010		2011 and beyond		Total

Long-Term Debt:
	Principal	$	190,206	$	708,696	$	2,339,746	$	3,238,648
	Interest ⁽¹⁾		169,844		579,272		754,339		1,503,455
Capital Leases ⁽²⁾			44,264		177,298		286,418		507,980
Operating Leases			4,806		19,829		43,312		67,947
Unconditional Power Purchases			32,759		114,815		285,755		433,329
Rocky Mtn.Lease Transactions ⁽³⁾			0		0		371,900		371,900
Chattahoochee O&M Agreements			20,000		80,000		100,000		200,000
Asset Retirement Obligations ⁽⁴⁾			0		0		3,026,017		3,026,017

Total		$	461,879	$	1,679,910	$	7,207,487	$	9,349,276

(1): Includes an interest rate assumption for variable rate debt.
(2): Amounts represent total rental payment obligations, not amortization of debt underlying the leases.
(3): Oglethorpe entered into a funding agreement with a highly rated entity to fund this obligation. For additional information, see "Off-Balance Sheet Arrangements – Rocky Mountain Lease Arrangments" 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 has financial agreements containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral (in the form of either letters of credit, surety bonds or cash) or termination of the agreement. The table below sets forth the more significant rating triggers contained in Oglethorpe's financial agreements.


Rating Triggers		S&P	Moody's	Fitch

Interest Rate Swaps
	Senior Secured	BBB-	Baa3	NA ⁽¹⁾
Rocky Mountain Lease
	Senior Secured	BBB	Baa2	BBB
	Senior Unsecured	BBB-	Baa3	BBB-

(1): NA = rating not included as a trigger in agreement

Under the interest rate swap arrangements, if Oglethorpe's rating from Standard & Poor's or Moody's falls below the levels shown in the table above, the swap counterparty has the option of (1) making swap payments based on an index rather than the actual variable rate on the bonds, or (2) causing an early termination of the swaps. In the event of a termination, either party could owe the other party a termination payment depending on the market value of the swap position. Oglethorpe estimates that a termination of the swaps on December 31, 2005 would have required Oglethorpe to make a termination payment (net of GTC's assumed percentage) of approximately $35 million. Except in situations where Oglethorpe voluntarily elects to terminate the interest rate swaps early, Oglethorpe has the right to pay a termination payment due to the swap counterparty over a term of up to five years. The swap arrangements extend for the life of the underlying bonds, which have sinking fund amortization. Therefore, all other things being equal, annual reductions in the outstanding principal amounts will reduce termination payments. For a further discussion of termination events under the swaps, see "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK – Interest Rate Risk –Interest Rate Swap Transactions."

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

Provisions in the RUS Loan Contract and certain PCB loan agreements contain covenants based on credit ratings that could result in increased interest rates or restrictions on issuing debt. Also, borrowing rates and commitment fees in the CFC line of credit agreement

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 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.

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% of Oglethorpe's assets), GTC assumed 16.86% 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, 2005, the total obligation assumed by GTC relating to outstanding PCB principal was $97 million. (See Note 5 of Notes to Financial Statements.) In 2006, GTC's estimated payments of principal and interest pursuant to this assumed obligation will be approximately $7 million.

Oglethorpe also remains secondarily liable for a 16.86% portion of Oglethorpe's interest rate swaps that were assumed by GTC in connection with the corporate restructuring. GTC's portion of the estimated maximum aggregate liability for termination payments under the swaps had such payments been due on December 31, 2005 would have been $7 million.

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

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 2005, the amount of the rental payments under the Facility Subleases and Facility Leases each totaled $56 million.

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

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

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 $89 million at December 31, 2005). 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, 2005, both the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions would have been higher by $714 million.

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

•: causing RMLC and Oglethorpe to renew the related Facility Leases and Facility Subleases for up to an additional 16 years and provide collateral satisfactory to the owner trusts,
•: leasing its undivided interest to a third party under a replacement lease, or
•: retaining the undivided interest for its own benefit.

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

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

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Interest Rate Risk

Oglethorpe is exposed to the risk of changes in interest rates due to the significant amount of financing obligations it has entered into, including variable rate debt and interest rate swap transactions. Oglethorpe's objective in managing interest rate risk is to maintain a balance of fixed and variable rate debt that will lower its overall borrowing costs within reasonable risk parameters. As part of this debt management strategy, Oglethorpe has a guideline of having between 15% and 30% variable rate debt to total debt. At December 31, 2005, Oglethorpe had 18% 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, 2005, 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
		2005			2006			2007			2008			2009			2010			Thereafter

Fixed Rate Debt
Beginning of year				$	2,395,884		$	2,212,071		$	2,053,882		$	1,888,104		$	1,713,676		$	1,552,856
Maturities					(183,813	)		(158,189	)		(165,778	)		(174,428	)		(160,820	)

End of year	$	2,650,768		$	2,212,071		$	2,053,882		$	1,888,104		$	1,713,676		$	1,552,856

Average interest rate on maturing fixed rate debt					5.78%			5.82%			5.85%			5.85%			5.93%			5.81%
Variable Rate Debt
Beginning of year				$	604,421		$	604,180		$	603,909		$	603,604		$	603,260		$	602,873
Maturities					(241	)		(271	)		(305	)		(344	)		(387	)

End of year	$	604,200		$	604,180		$	603,909		$	603,604		$	603,260		$	602,873

Average interest rate on maturing variable rate debt ⁽¹⁾					4.57%			4.57%			6.60%			6.60%			6.60%			3.67%
Interest Rate Swaps
Beginning of year				$	238,343		$	232,191		$	222,086		$	212,027		$	207,139		$	184,019
Maturities					(6,152	)		(10,105	)		(10,059	)		(4,888	)		(23,120	)

End of year	$	238,343		$	232,191		$	222,086		$	212,027		$	207,139		$	184,019

Average interest rate on maturing debt ⁽²⁾					5.83%			5.77%			5.78%			5.92%			5.67%			5.81%
Unrealized loss on swaps	$	(34,910	)

(1): 99% of the variable rate debt reflected in the above table relates to PCB debt with bullet maturities beyond 2010, with a weighted average interest rate of 3.18% at 1/1/06. Future variable interest rates for PCB debt are adjusted based on a forward BMA yield curve.
(2): Debt underlying the interest rate swaps is variable rate PCB debt that was swapped to a contractual fixed rate of interest in 1993, so the average interest rate on maturing debt represents the average of the two contractual fixed rates.

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 2.44% for all of 2005 and 3.18% at January 1, 2006. 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 to maturity. This optionality improves Oglethorpe's ability to manage its exposure to variable interest rates.

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

Interest Rate Swap Transactions

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

Under the swap arrangements, Oglethorpe is obligated to make periodic payments to AIG-FP based on a notional principal amount equal to the aggregate principal amount of the bonds outstanding during the period and a contractual fixed rate ("Fixed Rate"), and AIG-FP is obligated to make periodic payments to Oglethorpe based on a notional principal amount equal to the aggregate principal amount of the bonds outstanding during the period and a variable rate equal to the variable rate of interest accruing on the bonds during the period ("Variable Rate"). These payment obligations are netted, such that if the Variable Rate is less than the Fixed Rate, Oglethorpe makes a net payment to AIG-FP. Likewise, if the Variable Rate is higher than the Fixed Rate, Oglethorpe receives a net payment from AIG-FP. Thus, although changes in the Variable Rate affect whether Oglethorpe is obligated to make payments to AIG-FP or is entitled to receive payments from AIG-FP, the effective interest rate Oglethorpe pays with respect to the PCBs is not affected by changes in interest rates. The Fixed Rate on the 1993 bonds is 5.67% and the Fixed Rate on the 1994 bonds is 6.01%. At December 31, 2005, there was $177 million notional amount outstanding of 1993 bonds (carrying a variable rate of interest of 3.54%) and $110 millon notional amount outstanding of 1994 bonds (carrying a variable rate of interest of 3.58%). For the three years ended December 31, 2003, 2004 and 2005, Oglethorpe has made in connection with both interest rate swap arrangements combined net swap payments to AIG-FP (net of amounts assumed by GTC) of, $11.8 million, $11.0 million and $8.0 million, respectively.

The obligation of AIG-FP to make payments to Oglethorpe under the swap arrangements are guaranteed by AIG-FP's parent company, American International Group, Inc. ("AIG"). The senior unsecured debt obligations of AIG and AIG-FP are rated "AA" and "Aa2" by Standard and Poor's and Moody's, respectively.

Unless terminated, the swap arrangements will extend for the life of the underlying PCBs (through January 2016 and January 2019 for the 1993 bonds and 1994 bonds, respectivley). AIG-FP has limited rights to terminate the swaps only upon the occurrence of specified events of default or due to an Oglethorpe Downgrading. Termination Events related to rating downgrades are as follows:

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

•: Guarantor Downgrading (defined as AIG ratings below "A-" or "A3"); and
•: Bond Downgrading (defined as ratings on the underlying bonds below "AA-" or "Aa3"; the bonds are insured by a triple-A municipal bond insurer and therefore carry the same rating).

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

If the swap arrangements were to be terminated while the PCBs are still outstanding, Oglethorpe or AIG-FP may owe the other party a termination payment depending on a number of factors, including whether the fixed rate then being offered under comparable swap arrangements is higher or lower than the Fixed Rate. Oglethorpe estimates that its maximum aggregate liability (net of GTC's assumed percentage) for termination payments under both swap arrangements had such payments been due on December 31, 2005 would have been $35 million. Except in situations where Oglethorpe voluntarily elects to terminate the interest rate swaps early, Oglethorpe has the right to a term-out of any termination payment due to the swap counterparty for a term of up to five years.

Capital Leases

In December 1985, Oglethorpe sold and subsequently leased back from four purchasers its 60% undivided ownership interest in Scherer Unit No. 2. The capital leases provide that Oglethorpe's rental payments vary to the extent of interest rate changes associated with the debt used by the lessors to finance their purchase of undivided ownership shares in the unit. The debt currently consists of $118 million in serial facility bonds due June 30, 2011 with a 6.97% fixed rate of interest.

Oglethorpe entered into a power purchase and sale agreement with Doyle I, LLC to purchase all of the output from a five-unit gas-fired generation facility. The Doyle agreement is reported on Oglethorpe's balance sheet as a capital lease. The lease payments vary to the extent the interest rate on the lessor's debt varies from 6.00%. At December 31, 2005, the weighted average interest rate on the lease obligation was 5.86%.

Equity Price Risk

Oglethorpe maintains trust funds, as required by the NRC, to fund certain costs of nuclear decommissioning. (See Note 1 of Notes to Financial Statements.) As of December 31, 2005, these funds were invested in U.S. Government securities, domestic and international equities and global fixed income securities. By maintaining a portfolio that includes long-term equity investments, Oglethorpe intends to maximize the returns to be utilized to fund nuclear decommissioning, which in the long-term will better correlate to inflationary increases in decommissioning costs. However, the equity securities included in Oglethorpe's portfolio are exposed to price fluctuation in equity markets. A 10% decline in the value of the fund's equity securities as of December 31, 2005 would result in a loss of value to the fund of approximately $10 million. Oglethorpe actively monitors its portfolio by benchmarking the performance of its investments against certain indices and by maintaining, and periodically reviewing, established target allocation percentages of the assets in its trusts to various investment options. Because realized and unrealized gains and losses from investment securities held in the decommissioning fund are directly added to or deducted from the decommissioning reserve, fluctuations in equity prices do not affect Oglethorpe's net margin in the short-term.

Commodity Price Risk

Coal

Oglethorpe is also exposed to the risk of changing prices for fuels, including coal and natural gas. Oglethorpe has interests in 1,501 MW of coal-fired capacity (Plants Scherer and Wansley). Oglethorpe purchases coal under term contracts and in spot-market transactions. Oglethorpe's coal contracts provide volume flexibility and fixed prices. Oglethorpe anticipates that its existing contracts will provide fixed prices for all of its forecasted coal requirements in 2006. Additionally, such contracts will provide about 87% of Oglethorpe's coal requirements in 2007 and 63% of its 2008 coal requirements. The objective of Oglethorpe's coal procurement strategy is to ensure reliable coal supply and some price stability for the Members. Its strategy focuses on hedging requirements over a three-year time horizon, but permits opportunities to make purchases up to six years into the future. The procurement guidelines provide for layering in fixed prices by annually entering

into forward contracts for between 25% and 35% of the forecasted requirements, for a rolling three-year period.

Natural Gas

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

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

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

Oglethorpe 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, 2005, Oglethorpe would have received a net payment of approximately $1,158,000. If Oglethorpe's natural gas swaps had been terminated on March 20, 2006, Oglethorpe would have made a net payment of approximately $188,000.

Oglethorpe has obtained the Members' approval required by the New Business Model Member Agreement to continue to manage exposures to natural gas price risks for Members that elect to receive such services. Oglethorpe is providing natural gas price risk management services to 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.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index To Financial Statements

		Page
Statements of Revenues and Expenses, For the Years Ended December 31, 2005, 2004 and 2003		49
Balance Sheets, As of December 31, 2005 and 2004		50
Statements of Capitalization, As of December 31, 2005 and 2004		52
Statements of Cash Flows, For the Years Ended December 31, 2005, 2004 and 2003		53
Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Margin For the Years Ended December 31, 2005, 2004 and 2003		54
Notes to Financial Statements		55
Report of Management		73
Report of Independent Registered Public Accounting Firm		73

STATEMENTS OF REVENUES AND EXPENSES

For the years ended December 31, 2005, 2004 and 2003

			(dollars in thousands)
			2005			2004			2003

Operating revenues (Note 1):
	Sales to Members	$	1,136,463		$	1,279,465		$	1,167,605
	Sales to non-Members		33,060			33,307			35,948

Total operating revenues			1,169,523			1,312,772			1,203,553

Operating expenses:
	Fuel		365,073			290,106			234,172
	Production		251,830			248,084			253,865
	Purchased power (Note 9)		255,616			402,941			359,447
	Depreciation and amortization		153,030			153,126			141,301
	Accretion (Note 1)		33,996			20,456			7,815
	Income taxes (Note 3)		–			(3	)		(459	)
	Gain on sale of emission allowances (Note 10)		(83,098	)		–			–

Total operating expenses			976,447			1,114,710			996,141

Operating margin			193,076			198,062			207,412

Other income (expense):
	Investment income		36,060			33,310			23,092
	Amortization of deferred gains (Notes 1 and 4)		2,475			2,475			2,475
	Amortization of net benefit of Rocky Mountain transactions (Note 1)		3,185			3,185			3,185
	Allowance for equity funds used during construction (Note 1)		355			199			417
	Other (Note 1)		3,048			3,059			3,568

Total other income			45,123			42,228			32,737

Interest charges:
	Interest on long-term debt and capital leases		203,124			205,086			206,265
	Other interest		3,321			2,774			5,329
	Allowance for debt funds used during construction (Note 1)		(1,681	)		(1,473	)		(2,771	)
	Amortization of debt discount and expense		15,782			16,666			14,477

Net interest charges			220,546			223,053			223,300

Net margin		$	17,653		$	17,237		$	16,849

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

BALANCE SHEETS

December 31, 2005 and 2004

			(dollars in thousands)
			2005			2004

Assets
Electric plant (Notes 1, 4 and 6):
	In service	$	5,804,772		$	5,784,529
	Less: Accumulated provision for depreciation		(2,377,671	)		(2,237,192	)

			3,427,101			3,547,337
	Nuclear fuel, at amortized cost		94,159			87,941
	Construction work in progress		26,721			22,830

Total electric plant			3,547,981			3,658,108

Investments and funds (Notes 1 and 2):
	Decommissioning fund, at market		206,364			196,181
	Deposit on Rocky Mountain transactions, at cost		88,689			83,012
	Bond, reserve and construction funds, at market		7,252			8,051
	Investment in associated companies, at cost		38,696			33,959
	Long-term investments, at market		46,265			68,507
	Other, at cost		1,044			1,084

Total investments and funds			388,310			390,794

Current assets:
	Cash and cash equivalents, at cost (Note 1)		170,734			133,669
	Restricted cash and cash equivalents, at cost (Note 1)		16,156			11,781
	Restricted short-term investments, at cost (Note 1)		222,328			81,104
	Other short-term investments, at market		9,337			6,663
	Receivables (Note 1)		96,486			129,221
	Inventories, at average cost (Note 1)		94,574			100,927
	Prepayments and other current assets		5,171			4,118

Total current assets			614,786			467,483

Deferred charges:
	Premium and loss on reacquired debt, being amortized (Note 1)		121,431			134,575
	Deferred amortization of capital leases (Note 4)		108,790			110,422
	Deferred debt expense, being amortized (Note 1)		23,293			23,026
	Deferred nuclear outage costs, being amortized (Note 1)		16,993			10,880
	Deferred asset retirement obligations costs, being amortized (Note 1)		1,852			14,664
	Other		4,639			3,226

Total deferred charges			276,998			296,793

Total assets		$	4,828,075		$	4,813,178

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

BALANCE SHEETS

			(dollars in thousands)
			2005			2004

Equity and Liabilities
Capitalization (see accompanying statements):
	Patronage capital and membership fees (Note 1)	$	479,308		$	461,655
	Accumulated other comprehensive loss (Note 1)		(34,339	)		(46,896	)

			444,969			414,759
	Long-term debt		3,048,442			3,180,915
	Obligations under capital leases (Note 4)		304,897			324,326
	Obligation under Rocky Mountain transactions		88,689			83,012

Total capitalization			3,886,997			4,003,012

Current liabilities:
	Long-term debt and capital leases due within one year (Note 5)		217,743			190,835
	Accounts payable		56,516			67,149
	Accrued interest		54,221			40,176
	Accrued and withheld taxes		29,041			9,945
	Members' advances (Note 1)		74,471			–
	Other current liabilities		9,293			11,583

Total current liabilities			441,285			319,688

Deferred credits and other liabilities:
	Gain on sale of plant, being amortized (Note 4)		40,960			43,434
	Net benefit of Rocky Mountain transactions, being amortized (Note 1)		66,892			70,078
	Asset retirement obligations (Note 1)		267,406			248,295
	Accumulated retirement costs for other obligations		56,913			54,272
	Interest rate swap arrangements (Note 2)		34,910			45,254
	Other		32,712			29,145

Total deferred credits and other liabilities			499,793			490,478

Total equity and liabilities		$	4,828,075		$	4,813,178

Commitments and Contingencies (Notes 1, 5, 9, 11 and 12)

STATEMENTS OF CAPITALIZATION

December 31, 2005 and 2004

				(dollars in thousands)
				2005			2004

Long-term debt (Note 5):
	Mortgage notes payable to the Federal Financing Bank ("FFB") at interest rates varying from 3.89% to 8.43% (average rate of 5.80% at December 31, 2005) due in quarterly installments through 2025		$	2,324,661		$	2,443,229
	Mortgage notes payable to Rural Utilities Service ("RUS") at an interest rate of 5% due in monthly installments through 2021			10,990			11,509
	Mortgage notes issued in conjunction with the sale by public authorities of pollution control revenue bonds ("PCBs"):
		• Series 1992A Serial bonds, 6.55% to 6.80%, due serially from 2006 through 2012		60,232			66,841
		• Series 1993A Adjustable tender bonds, 3.54%, due 2006 through 2016		146,856			149,828
		• Series 1994A Adjustable tender bonds, 3.58%, due 2006 to 2019		91,487			91,487
		• Series 1998A and 1998B Adjustable tender bonds, 2.80% to 3.35%, due 2019		180,343			180,343
		• Series 1999A and 1999B Adjustable tender bonds, 3.75%, due 2020		88,775			88,775
		• Series 2000 Adjustable tender bonds, 3.75%, due 2021		21,950			21,950
		• Series 2001 Adjustable tender bonds, 3.75%, due 2022		22,825			22,825
		• Series 2002A and 2002B Auction rate bonds, 3.15% to 3.33%, due 2018		91,990			91,990
		• Series 2002 and 2002C Adjustable tender bonds, 3.60% to 3.75%, due 2018		30,075			30,075
		• Series 2003A and 2003B Auction rate bonds, 2.80% to 3.14%, due 2024		133,345			133,345
		• Series 2004 Auction rate bonds, 3.15% due 2020		11,525			11,525
		• Series 2005 Auction rate bonds, 2.95%, due 2040		15,865			–
	CoBank, ACB notes payable:
		• Transmission mortgage note payable: fixed at 4.57% through March 2, 2008, due in bimonthly installments through November 1, 2018		1,574			1,623
		• Transmission mortgage note payable: fixed at 4.57% through March 2, 2008, due in bimonthly installments through September 1, 2019		6,155			6,319

Total long-term debt				3,238,648			3,351,664
Obligations under capital leases, (Note 4)				332,434			344,412
Obligation under Rocky Mountain transactions, (Note 1)				88,689			83,012
Patronage capital and membership fees (Note 1)				479,308			461,655
Accumulated other comprehensive loss (Note 1)				(34,339	)		(46,896	)

	Subtotal			4,104,740			4,193,847
		Less: long-term debt and capital leases due within one year		(217,743	)		(190,835	)

Total capitalization			$	3,886,997		$	4,003,012

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

STATEMENTS OF CASH FLOWS

For the years ended December 31, 2005, 2004 and 2003

					(dollars in thousands)
					2005			2004			2003

Cash flows from operating activities:
	Net margin			$	17,653		$	17,237		$	16,849

	Adjustments to reconcile net margin to net cash provided by operating activities:
		Depreciation and amortization, including nuclear fuel			225,366			228,353			221,610
		Net accretion cost			33,996			20,456			7,815
		Amortization of deferred gains			(2,475	)		(2,475	)		(2,475	)
		Amortization of net benefit of Rocky Mountain transactions			(3,185	)		(3,185	)		(3,185	)
		Allowance for equity funds used during construction			(355	)		(199	)		(417	)
		Deferred nuclear outage costs			(23,654	)		(13,469	)		(14,775	)
		Other			(2,196	)		(3,573	)		2,159
	Change in operating assets and liabilities:
		Receivables			34,174			(17,742	)		(24,168	)
		Inventories			6,353			4,411			(12,053	)
		Prepayments and other current assets			106			118			(1,270	)
		Accounts payable			(10,633	)		3,590			13,283
		Accrued interest			14,045			33,018			201
		Accrued and withheld taxes			19,096			(10,012	)		19,424
		Other current liabilities			(2,155	)		2,340			(4,104	)

	Total adjustments				288,483			241,631			202,045

Net cash provided by operating activities					306,136			258,868			218,894

Cash flows from investing activities:
	Property additions				(75,065	)		(65,798	)		(171,126	)
	Activity in decommissioning fund – Purchases				(690,224	)		(905,803	)		(756,044	)
			– Proceeds		677,085			884,339			746,757
	Activity in bond, reserve and construction funds – Purchases				(1,064	)		(7,967	)		(27,189	)
			– Proceeds		1,777			21,449			31,842
	Net cash received from merger				–			–			18,273
	(Increase) decrease in restricted cash and cash equivalents				(4,375	)		121,564			(103,244	)
	(Increase) decrease in restricted and other short-term investments				(132,861	)		8,501			(4,028	)
	(Increase) decrease in investment in associated companies				(4,268	)		(2,308	)		712
	Increase in other long-term investments – Purchases				(471,276	)		(606,167	)		(385,338	)
			– Proceeds		483,525			563,814			358,338
	Increase in Members' advances				74,471			–			–
	Decrease in notes receivable				–			–			745
	Increase in equipment prepayments				(2,563	)		–			–
	Proceeds from sale of generation equipment				–			–			21,799

Net cash (used in) provided by investing activities					(144,838	)		11,624			(268,503	)

Cash flows from financing activities:
	Debt proceeds				24,512			11,525			700,124
	Debt payments				(149,697	)		(210,330	)		(390,582	)
	Debt related costs				(2,905	)		(10,572	)		(8,680	)
	Decrease in notes payable (Note 5)				–			–			(297,776	)
	Increase in note receivable (Note 5)				–			–			(11,105	)
	Major overhaul accrual financed by Members				3,857			6,069			2,903

Net cash used in financing activities					(124,233	)		(203,308	)		(5,116	)

Net increase (decrease) in cash and cash equivalents					37,065			67,184			(54,725	)
Cash and cash equivalents at beginning of year				$	133,669			66,485			121,210

Cash and cash equivalents at end of year					170,734		$	133,669		$	66,485

Supplemental cash flow information:
	Cash paid for –
	Interest (net of amounts capitalized)			$	190,719		$	173,369		$	208,622
	Income taxes				–			–			–

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

STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND
ACCUMULATED OTHER COMPREHENSIVE MARGIN

For the years ended December 31, 2005, 2004 and 2003

			(dollars in thousands)
			Patronage Capital and Membership Fees		Accumulated Other Comprehensive Margin (Loss)			Total


Balance at December 31, 2002		$	427,569	$	(55,751	)	$	371,818

Components of comprehensive margin in 2003
	Net margin		16,849					16,849
	Unrealized gain on interest rate swap arrangements				8,527			8,527
	Unrealized loss on available-for-sale securities				(2,340	)		(2,340	)
	Unrealized loss on financial gas hedges				(250	)		(250	)

Total comprehensive margin								22,786

Balance at December 31, 2003			444,418		(49,814	)		394,604

Components of comprehensive margin in 2004
	Net margin		17,237					17,237
	Unrealized gain on interest rate swap arrangements				4,662			4,662
	Unrealized loss on available-for-sale securities				(888	)		(888	)
	Unrealized loss on financial gas hedges				(856	)		(856	)

Total comprehensive margin								20,155

Balance at December 31, 2004			461,655		(46,896	)		414,759

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
	Unrealized gain on financial gas hedges				1,295			1,295

Total comprehensive margin								30,210

Balance at December 31, 2005		$	479,308	$	(34,339	)	$	444,969

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

NOTES TO FINANCIAL STATEMENTS

For the years ended December 31, 2005, 2004 and 2003

1. Summary of significant accounting policies:

a. Business description

Oglethorpe Power Corporation ("Oglethorpe") is an electric membership corporation incorporated in 1974 and headquartered in suburban Atlanta. From 1974 to 2004, Oglethorpe provided wholesale electric power, on a not-for-profit basis, to 39 of Georgia's 42 Electric Membership Corporations ("EMCs") from a combination of generating units totaling 4,744 megawatts ("MW") of capacity and power purchase agreements totaling 550 MW of capacity. However, effective January 1, 2005, one of these EMCs withdrew from membership in Oglethorpe. These 38 electric distribution cooperatives ("Members") in turn distribute energy on a retail basis to approximately 3.7 million people across two-thirds of the State.

b. Basis of accounting

Oglethorpe follows generally accepted accounting principles and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission ("FERC") as modified and adopted by the Rural Utilities Service ("RUS").

The preparation of financial statements in conformity with generally accepted accounting principles 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, 2005 and 2004 and the reported amounts of revenues and expenses for each of the three years ending December 31, 2005. 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 their electricity purchases from Oglethorpe.

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 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 margin or (loss)

The table below provides a detail of the beginning and ending balance for each classification of other comprehensive margin or (loss) 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 Margin (see Note 2). Oglethorpe's effective tax rate is zero; therefore, all amounts below are presented net of tax.


Accumulated Other Comprehensive Margin (Loss)
		(dollars in thousands)
		Interest Rate Swap Arrangements			Available- for-sale Securities			Financial Gas Hedges			Total

Balance at December 31, 2002	$	(58,443	)	$	1,722		$	970		$	(55,751	)

Unrealized gain/(loss)		8,527			(2,838	)		7,501			13,190
(Gain) loss reclassified to net margin		–			498			(7,751	)		(7,253	)

Balance at December 31, 2003		(49,916	)		(618	)		720			(49,814	)

Unrealized gain/(loss)		4,662			50			2,119			6,831
(Gain) loss reclassified to net margin		–			(938	)		(2,975	)		(3,913	)

Balance at December 31, 2004		(45,254	)		(1,506	)		(136	)		(46,896	)

Unrealized gain/(loss)		10,344			918			2,077			13,339
(Gain) loss reclassified to net margin		–			–			(782	)		(782	)

Balance at December 31, 2005	$	(34,910	)	$	(588	)	$	1,159		$	34,339

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 2003, 2004 and 2005, 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 consist of electric sales to power companies and from sales to LG&E Energy Marketing Inc. ("LEM") and Morgan Stanley Capital Group, Inc. ("Morgan Stanley") under their power marketer arrangements with Oglethorpe. All off-system sales are recorded as revenues from non-Members and are recognized when service is rendered.

Revenues from Jackson EMC, Cobb EMC and Sawnee EMC, three of Oglethorpe's Members, accounted for 13.0%, 12.8% and 10.4% in 2005, respectively, of Oglethorpe's total operating revenues. Revenues from Jackson EMC and Cobb EMC accounted for 12.0% and 10.1% in 2004 and 11.6% and 10.6% in 2003, 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 2005, 2004 and 2003 amounted to $44,395,000, $46,460,000 and $46,628,000, 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. Effective June 2000, an on-site dry storage facility for Plant Hatch became 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 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.

The Energy Policy Act of 1992 required that utilities with nuclear plants be assessed over a 15-year period an amount which will be used by DOE for the decontamination and decommissioning of its nuclear fuel enrichment facilities. The amount of each utility's assessment was based on its past purchases of nuclear fuel enrichment services from DOE. Based on its ownership in Plants Hatch and Vogtle, Oglethorpe has a remaining nuclear fuel asset of approximately $2,703,000, which is being amortized to nuclear fuel expense over the next 2 years. Oglethorpe has also recorded an obligation to DOE which approximated $1,181,000 at December 31, 2005 (included in Other current liabilities and Other deferred credits and other liabilities on the accompanying balance sheets).

i. Asset retirement obligations

In January 2003, Oglethorpe adopted Statement of Financial Accounting Standards ("SFAS") No. 143, "Accounting for Asset Retirement Obligations." The statement provides accounting and reporting standards for recognizing obligations related to costs associated with the retirement of long-lived assets. SFAS No. 143 requires obligations associated with the retirement of long-lived assets to be recognized at their fair value in the period in which they are incurred if a reasonable estimate of fair value can be made. The fair value of the asset retirement costs must be capitalized as part of the carrying amount of the long-lived asset and

subsequently allocated to expense using a systematic and rational method over the asset's useful Life. Any subsequent changes to the fair value of the liability due to passage of time or changes in the amount or timing of estimated cash flows must be recognized as an accretion expense.

The liability recognized under SFAS No. 143 primarily relates to Oglethorpe's nuclear facilities. Oglethorpe also recognized retirement obligations for ash handling facilities at the coal-fired plants and solid waste landfills located at certain generating facilities. In addition, effective December 31, 2005, Oglethorpe adopted Financial Accounting Standards Board ("FASB") Interpretation No. 47 ("Interpretation No. 47"), "Conditional Asset Retirement Obligations," which requires that an asset retirement obligation be recorded even though the timing and/or method of settlement are conditional on future events. Prior to December 2005, Oglethorpe did not recognize asset retirement obligations for asbestos removal because the timing of their retirements was dependent on future events. Oglethorpe recorded additional asset retirement obligations of $3.0 million for asbestos removal with an offsetting increase to regulatory assets.

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 that the annual difference will be approximately $1,000,000 for the next several years.

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.

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


		(dollars in thousands)
		Balance at 12/31/04		Liabilities Incurred		Accretion		Change in Cash Flow Estimate		Balance at 12/31/05

Nuclear decommissioning	$	243,939	$	–	$	15,839	$	–	$	259,778
Other		4,356		2,989		283		–		7,628

Total	$	248,295	$	2,989	$	16,122	$	–	$	267,406

As previously discussed, Oglethorpe is deferring the timing differences between cost recognition under SFAS No. 143 and cost recovery for rate making. For 2005 and 2004, these timing differences resulted in a decrease to the regulatory asset of $17,874,000, and $5,316,000, respectively.

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.

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 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, 2005 and 2004, equity securities comprised 46% and 40% of the funds and fixed income securities comprised 54% and 60%, 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.

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		2003		2003		2003		2003
Expected start date of decommissioning		2034		2038		2027		2029
Estimated costs based on site study:
In year 2003 dollars	$	144,000	$	184,000	$	154,000	$	181,000

Oglethorpe has not recorded any provision for decommissioning during the years 2005, 2004 and 2003 because the balance in the decommissioning trust fund at December 31, 2005 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 3.11%. Oglethorpe assumes a 7% earnings rate for its decommissioning trust fund assets. Since inception (1990), the nuclear decommissioning trust fund has produced a return in excess of 8%. 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 2005, 2004 and 2003 were as follows:


	Range of Useful Life in years*	2005	2004	2003

Steam production	49-55	1.97%	1.97%	2.02%
Nuclear production	37-52	2.54%	2.58%	2.50%
Hydro production	50	2.00%	2.00%	2.00%
Other production	27-33	3.03%	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 2005.

Depreciation expense for the years 2005, 2004 and 2003 was $152,558,000, $152,653,000, and $140,837,000, respectively.

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, 2005, 2004 and 2003, the allowance for funds used during construction ("AFUDC") rates used were 5.96%, 5.85% and 6.46%, 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. Both 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, 2005 and 2004, all of the funds were invested in either U.S. Government securities or repurchase agreements.

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 and cash equivalents

The balances at December 31, 2005 and 2004, $16,156,000 and $11,781,000, respectively, were utilized

in January 2006 and 2005 for payment of principal on certain PCBs, respectively.

p. Restricted short-term investments

Oglethorpe entered into a Cushion of Credit Account with the RUS in July 2004. At December 31, 2005 and 2004, Oglethorpe had on deposit with the RUS $222,328,000 and $81,104,000, respectively, restricted for future RUS/Federal Financing Bank ("FFB") debt service payments. The deposit earns interest at a RUS guaranteed rate of 5% per annum.

q. 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, 2005 and 2004, fossil fuels inventories were $14,436,000 and $24,747,000, respectively. Inventories for spare parts at December 31, 2005 and 2004 were $80,138,000 and $76,180,000, respectively.

r. Deferred charges

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 cost as deferred debt expense. Deferred debt expense is being amortized to expense on a straight-line basis over the life of the respective debt issues.

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, 2005, the remaining amortization periods for premium and loss on reacquired debt range from approximately 2 to 22 years.


		(dollars in thousands)
		Balance at 12/31/04		Additions		Amortization			Balance at 12/31/05

Nuclear refueling outage costs	$	10,880	$	23,655	$	(17,542	)	$	16,993
Debt issuance costs		23,026		2,322		(2,055	)		23,293
Premium (loss) on reacquired debt		134,575		583		(13,727	)		121,431

s. 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.

t. 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. 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 "discontinued projects" and "other regulatory assets" are included on the balance sheets, under the caption deferred charges, in the line item "Other."

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 were reflected on the accompanying balance sheets as of December 31, 2005 and 2004:


		(dollars in thousands)
		2005			2004

Premium and loss on reacquired debt	$	121,431		$	134,575
Deferred amortization of capital leases		108,790			110,422
Deferred nuclear refueling outage costs		16,993			10,880
Discontinued projects		1,963			2,453
Asset retirement obligations		1,852			14,664
Other regulatory assets		631			1,274
Accumulated retirement costs for other obligations		(56,913	)		(54,272	)
Net benefit of Rocky Mountain transactions		(66,892	)		(70,078	)

Total	$	127,855		$	149,918

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 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 22 years, except for the asset retirement obligations regulatory assets which has a recovery period of 13 to 40.5 years. The remaining refund period for the regulatory liabilities are approximately 21 years for the Rocky Mountain transactions and over the lives of the plants for accumulated retirement costs for other obligations.

u. Other income (expense)

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


		(dollars in thousands)
		2005			2004			2003

Capital credits from associated companies (Note 2)	$	1,908		$	1,610		$	2,078
Net revenue from Georgia Transmission Corporation ("GTC") & Georgia System Operations Corporation ("GSOC") for shared A&G costs		1,501			1,579			1,732
Miscellaneous other		(361	)		(130	)		(242	)

Total	$	3,048		$	3,059		$	3,568

v. Members' advances

Members' advances represent amounts received from the Members for prepayment of their monthly power bill. The prepayment program began in 2005. These payments earn a discount on the Member's power bill from Oglethorpe. These prepayments are deposited into the Cushion of Credit (restricted short-term investments) with the RUS by Oglethorpe. It is currently expected that these amounts will be utilized by the second quarter of 2006.

w. Presentation

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

x. New accounting pronouncements

In March 2005, the FASB issued Interpretation No. 47. This Interpretation clarifies the term "conditional asset retirement obligation" as used in SFAS No. 143, "Accounting for Asset Retirement Obligations." Interpretation No. 47 indicates that a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of Oglethorpe. The obligation to perform the asset retirement activity is unconditional even though uncertainty may exist about the timing and/or method of settlement. Thus, the timing and/or method of settlement may be conditional on a future event. Accordingly, Oglethorpe is required to recognize a liability for the fair value of a conditional asset retirement obligation if the fair value of the liability can be reasonably estimated. This Interpretation also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. At December 31, 2005, Oglethorpe recorded additional asset retirement obligations of $3.0 million for asbestos removal. The adoption of Interpretation No. 47 did not have any effect on net margin. For further discussion see"Asset Retirement Obligations" in Note 1.

In February 2006, the FASB issued SFAS No. 155, "Accounting for Certain Hybrid Financial Instruments," an amendment of FASB Statements No. 133 and 140. This statement resolves issues addressed in SFAS No. 133 Implementation Issue No. D41, "Application of Statement 133 to Beneficial Interests in Securitized Financial Assets." SFAS No. 155 is effective for fiscal years beginning after September 15, 2006. Oglethorpe will implement this standard effective January 1, 2007. Oglethorpe does not expect this statement to have an impact on its financial statements.

y. Proposed accounting interpretation

In July 2005, the FASB issued an Exposure Draft of a proposed Interpretation, "Accounting for Uncertain Tax Positions – an Interpretation of FASB Statement No. 109." The objective of the Proposed Interpretation is to clarify the accounting for uncertain tax positions. Generally, an entity would be required to recognize, in its financial statements, the best estimate of the impact of a tax position only if that position is more likely than not of being sustained on audit based solely on the technical merits of the position. The tax position should be derecognized when it is no longer more likely than not of being sustained. Oglethorpe is monitoring developments of the Proposed Interpretation and is assessing the impact that the Proposed Interpretation may have on its financial statements. Oglethorpe cannot predict what actions the FASB will take or how such actions might ultimately affect Oglethorpe's financial position or results of operations.

2. Fair value of financial instruments:

A detail of the estimated fair values of Oglethorpe's financial instruments as of December 31, 2005 and 2004 is as follows:


			(dollars in thousands)
			2005					2004
			Cost		Fair Value			Cost		Fair Value

Other short-term investments		$	9,470	$	9,337		$	7,217	$	6,663

Long-term investments		$	46,528	$	46,265		$	69,353	$	68,507

Bond, reserve and construction funds:
	U. S. Government securities	$	6,318	$	6,127		$	7,179	$	7,074
	Repurchase agreements		1,125		1,125			977		977

Total		$	7,443	$	7,252		$	8,156	$	8,051

Decommissioning fund:
	U. S. Government securities	$	20,335	$	20,258		$	18,219	$	18,244
	Corporate bonds		77,727		74,413			16,626		16,429
	Equity securities		85,222		95,909			68,174		78,545
	Asset-backed securities		5,838		5,819			4,166		4,031
	Other bonds		3,133		3,007			1,783		1,825
	Cash and money market securities		6,958		6,958			77,107		77,107

Total		$	199,213	$	206,364		$	186,075	$	196,181

Long-term debt		$	3,048,442	$	3,303,105		$	3,180,915	$	3,444,996

Interest rate swap		$	–	$	(34,910	)	$	–	$	(45,254	)

Financial gas hedges		$	–	$	1,159		$	–	$	(136	)

Oglethorpe uses the methods and assumptions described below to estimate the fair value of each class

of financial instruments. For cash and cash equivalents and restricted cash and cash equivalents, the carrying amount approximates fair value because of the short-term maturity of those instruments. Restricted short-term investments represent deposits with the RUS, restricted for future RUS/FFB debt service payments and its fair value approximates cost. 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 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, 2005.

Derivative instruments

Effective January 1, 2001, Oglethorpe adopted SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities." 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.

Under the interest rate swap arrangements, Oglethorpe makes payments to the counterparty based on the notional principal at a contractually fixed rate and the counterparty makes payments to Oglethorpe based on the notional principal at the existing variable rate of the refunding bonds. The differential to be paid or received is accrued as interest rates change and is recognized as an adjustment to interest expense. Oglethorpe entered into the swap arrangements for the purpose of securing a fixed rate lower than otherwise would have been available to Oglethorpe had it issued fixed rate bonds. For the Series 1993A notes, the notional principal at December 31, 2005 was $146,856,000 and the fixed swap rate is 5.67% (the variable rate at December 31, 2005 and 2004 was 3.54% and 1.99%, respectively). With respect to the Series 1994A notes, the notional principal at December 31, 2005 was $91,487,000 and the fixed swap rate is 6.01% (the variable rate at December 31, 2005 and 2004 was 3.58% and 2.00%, respectively). The notional principal amount is used to measure the amount of the swap payments and does not represent additional principal due to the counterparty. The swap arrangements extend for the life of the refunding bonds, with reductions in the outstanding principal amounts of the refunding bonds causing corresponding reductions in the notional amounts of the swap payments.

A portion (16.86%) of the interest rate swap arrangements was assumed by GTC in connection with a corporate restructuring. Oglethorpe has classified its portion of 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, 2005 was an unrealized loss of $34,910,000 representing the estimated payment Oglethorpe would pay if the swap arrangements were terminated.

Oglethorpe has entered into natural gas financial contracts that are classified, pursuant to SFAS 133, as cash flow hedges. Oglethorpe utilizes natural gas financial contracts in managing its exposure to fluctuations in the market price of natural gas. The fair value of Oglethorpe's financial gas hedges is based on the quoted market value for such natural gas financial contracts. At December 31, 2005, Oglethorpe's estimated fair value of these natural gas contracts was an unrealized gain in other comprehensive margin of $1,159,000.

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. 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, 2005, $1,159,000 of after-tax deferred gains in OCM are expected to be reclassified to margins during the next 12 months as the hedged interest and fuel payments occur. Due to the volatility of interest rates and natural gas prices, the value in OCM is subject to change prior to its reclassification into margins.

Investments in debt and equity securities

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

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, 2005 and 2004. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 48% 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. Oglethorpe has the intent and ability to hold these investments until recovery of fair value and thus does not consider these losses to be other than temporary.

The following table summarizes the unrealized gains and losses on the available-for-sale investments as of December 31, 2005, 2004 and 2003:


		(dollars in thousands)
		As of December 31,
		2005			2004			2003

Gross unrealized gains	$	13,366		$	10,642		$	16,959
Gross unrealized losses	$	(6,802	)	$	(2,041	)	$	(1,739	)

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
2005		Cost		Gains		Losses			Fair Value

Equity	$	85,222	$	12,835	$	(2,148	)	$	95,909
Debt		170,474		531		(4,654	)		166,351
Other		6,958		–		–			6,958

Total	$	262,654	$	13,366	$	(6,802	)	$	269,218

		Gross Unrealized
2004		Cost		Gains		Losses			Fair Value

Equity	$	68,174	$	10,446	$	(75	)	$	78,545
Debt		125,520		196		(1,966	)		123,750
Other		77,107		–		–			77,107

Total	$	270,801	$	10,642	$	(2,041	)	$	279,402

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, 2005 and 2004 are as follows:


		(dollars in thousands)
		2005				2004
		Cost		Fair Value		Cost		Fair Value

Due within one year	$	58,054	$	56,933	$	87,537	$	86,124
Due after one year through five years		37,186		35,591		21,497		21,089
Due after five years through ten years		16,067		15,695		2,526		2,530
Due after ten years		59,167		58,132		13,960		14,007

Total	$	170,474	$	166,351	$	125,520	$	123,750

The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2005, 2004 and 2003:


		(dollars in thousands)
		For the years ended December 31,
		2005			2004			2003

Gross realized gains	$	11,366		$	25,429		$	15,256
Gross realized losses	$	(4,010	)	$	(8,631	)	$	(8,680	)
Proceeds from sales	$	678,862		$	905,788		$	778,599

Investment in associated companies, at cost

Investments in associated companies were as follows at December 31, 2005 and 2004:


		(dollars in thousands)
		2005		2004

National Rural Utilities Cooperative Finance Corp. ("CFC")	$	13,976	$	13,977
CoBank, ACB		4,225		4,027
Georgia Transmission Corporation ("GTC")		10,228		8,842
Georgia System Operations Corporation ("GSOC")		5,504		4,736
Other		4,763		2,377

Total	$	38,696	$	33,959

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 2010.

Included in Other, is Oglethorpe's investment in CT Parts LLC of $3,364,000. Such investment is recorded at cost. 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.

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 2006, RMLC will be required to

make basic rent payments totaling $63,934,000 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 the high credit rating of the payment undertaker.

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

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.

Effective January 1, 2002, due to a change in its Bylaws, Oglethorpe began to allocate as patronage its patronage-sourced income as computed for Federal income tax purposes rather than its book net margin, which historically had been allocated as patronage. In addition, recent legal developments have clarified the scope of what constitutes patronage-sourced income. Based on these legal developments, Oglethorpe, after consultation with its tax advisors, believes that the sale of power to non-members constitutes patronage-sourced income. Consequently, Oglethorpe anticipates that all temporary differences, including those relating to non-member power sales, that reverse in the future will give rise to patronage-sourced income that will be offset by a patronage dividends deduction.

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.

A detail of the provision for income taxes in 2005, 2004 and 2003 is shown as follows:


			(dollars in thousands)
			2005		2004			2003

Current
	Federal	$	–	$	(3	)	$	(459)
	State		–		–			–

			–		(3	)		(459)

Deferred
	Federal		–		–			–
	State		–		–			–

			–		–			–

Income taxes charged to operations			–	$	(3	)	$	(459)

The difference between the statutory federal income tax rate on income before income taxes and Oglethorpe's effective income tax rate is summarized as follows:


	2005		2004		2003

Statutory federal income tax rate	35.0	%	35.0	%	35.0	%
Patronage exclusion	(35.0	%)	(35.1	%)	(34.7	%)
Tax credits	0.0	%	0.0	%	(2.6	%)
Other	0.0	%	0.1	%	(0.3	%)

Effective income tax rate	0.0	%	0.0	%	(2.6	%)

The components of the net deferred tax assets as of December 31, 2005 and 2004 were as follows:


			(dollars in thousands)
			2005			2004

Deferred tax assets
	Net operating losses	$	249,540		$	332,428
	Tax credits (alternative minimum tax and other)		1,848			2,037

			251,388			334,465
	Less: Valuation allowance		(251,388	)		(334,465	)

Net deferred tax assets			–			–

Deferred tax liabilities
	Depreciation		–			–

			–			–

Net deferred tax liabilities		$	–		$	–

As of December 31, 2005, Oglethorpe has federal tax net operating loss carryforwards ("NOLs") and alternative minimum tax credits ("AMT") as follows:


			(dollars in thousands)

Expiration Date			Alternative Minimum Tax Credits		Tax Credits		NOLs

	2006	$	–	$	–	$	209,009
	2007		–		–		86,779
	2008		–		–		94,927
	2009		–		–		96,394
	2010		–		–		77,970
	2018		–		–		61,533
	2019		–		–		10,516
	2020		–		–		4,362
	2021		–		–		–
	None		1,848		–		–

		$	1,848	$	–	$	641,490

The NOL expiration dates start in the year 2006 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 2004 to 2005 was the result of the reduction in deferred tax assets due to the expiration of tax credits and net operating losses. Pursuant to the Job Creation and Worker Assistance Act of 2002, in 2003 Oglethorpe carried back 2001 AMT loss to offset AMT paid in 1997. In 2004 and 2003, $3,000 and $459,000, respectively, was refunded to Oglethorpe. As a result, Oglethorpe's AMT credit carryforwards have been reduced by the amount that was realized due to the carryback claim. It is not likely that the remaining AMT credit will be realized.

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, 2005 are as follows:


Year Ending December 31,			(dollars in thousands)

			Scherer Unit No. 2			Doyle			Total

	2006	$	31,817		$	12,447		$	44,264
	2007		31,871			12,447			44,318
	2008		31,897			12,447			44,344
	2009		31,882			12,447			44,329
	2010		31,860			12,447			44,307
	2011-2021		218,335			68,083			286,418

Total minimum lease payments			377,662			130,318			507,980
	Add: 2005 principal and interest (1)		21,104			–			21,104
	Less: Amount representing interest		(163,068	)		(33,582	)		(196,650	)

	Present value of net minimum lease payments		235,698			96,736			332,434
	Less: Current portion		(20,709	)		(6,828	)		(27,537	)

	Long-term balance	$	214,989		$	89,908		$	304,897

(1): Amount represents principal and interest payments due December 31, 2005 but paid January 3, 2006 because due date was a holiday.

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, 2005, the weighted average interest rate on the Doyle lease obligation was 5.86%.

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

In November 2005, Oglethorpe completed a refunding transaction whereby $15,865,000 of PCBs were issued. The proceeds were used to make PCB principal payments in the same amount that were due on January 1, 2006. In conjunction with this transaction, $1,032,000 was released from debt service reserve funds 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 secured PCBs were assumed by GTC, including 16.86% of the PCBs that were refinanced in November 2005. However, GTC agreed with Oglethorpe not to participate in this $15,865,000 refinancing to the extent of their assumed obligation in the PCBs. Pursuant to this agreement, Oglethorpe provided a discount to GTC of approximately $803,000 on the $2,675,000 of principal payments due from GTC in connection with such refinancings. This $803,000 loss with the 2006 retirement will be reported, together with the unamortized transaction costs, as a deferred charge on Oglethorpe's balance sheet and will be amortized over three and half years as approved by RUS.

The annual interest requirement for 2006 is estimated to be $200,306,000.

Maturities for the long-term debt and amortization of the capital lease obligations through 2010 are as follows:


		(dollars in thousands)
		2006			2007		2008		2009		2010

FFB	$	176,230	⁽¹⁾	$	150,117	$	157,182	$	165,269	$	151,059
RUS		545			573		603		634		666
CoBank		241			271		305		344		387
PCBs ⁽²⁾		13,190			17,604		18,053		13,414		32,215

		190,206			168,565		176,143		179,661		184,327
Capital leases ⁽³⁾		27,537			21,081		22,873		24,876		27,121

Total	$	217,743		$	189,646	$	199,016	$	204,537	$	211,448

(1): Amount includes a $33 million quarterly principal payment due December 31, 2005 but paid January 3, 2006 because due date was a holiday.
(2): Amounts reflect only Oglethorpe's 83.14% share of the PCB maturities. The 2006 maturities were refinanced in a November 2005 transaction and a plan is in place to refinance the 2007 maturities in the fourth quarter of 2006.
(3): Amounts reflect the annual amortization of debt portion of capital lease obligations.

The weighted average interest rate for long-term debt and capital leases was 5.42% at December 31, 2005.

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, 2005 or 2004.

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 $300,000,000 committed backup line of credit that expires in September 2007. In addition to providing dedicated support for commercial paper, the facility may also be used for working capital and for general corporate purposes. However, any amounts drawn under the facility for working capital or general purposes 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, 2005 or 2004.

6. Electric plant and related agreements:

Oglethorpe and GPC have entered into agreements providing for the purchase and subsequent joint operation of certain of GPC's electrical 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, 2005 is as follows:


				(dollars in thousands)
Plant				Investment		Accumulated Depreciation

In-service
	Owned property
		Vogtle Units No. 1 & No. 2 (Nuclear – 30% ownership)	$	2,741,940	$	1,232,295
		Hatch Units No. 1 & No. 2 (Nuclear – 30% ownership)		583,834		314,837
		Wansley Units No. 1 & No. 2 (Fossil – 30% ownership)		225,771		103,649
		Scherer Unit No. 1 (Fossil – 60% ownership)		484,456		240,942
		Rocky Mountain Units No. 1, No. 2 & No. 3 (Hydro – 74.6% ownership)		556,137		116,827
		Wansley(Combustion Turbine – 30% ownership)		3,606		2,257
		Talbot(Combustion Turbine – 100% ownership)		278,948		27,503
		Chattahoochee(Combined cycle – 100% ownership)		296,719		25,575
		Generation step-up substations		103,576		66,495
		Other		62,999		32,758
Property under capital leases
		Doyle(Combustion Turbine – 100% leasehold)		126,990		41,597
		Scherer Unit No. 2(Fossil – 60% leasehold)		339,796		172,936

Total in-service			$	5,804,772	$	2,377,671

Construction work in progress
	Generation improvements		$	26,127
	Other			594

Total construction work in progress			$	26,721

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.

7. Employee benefit plans:

Oglethorpe has a money purchase pension plan. Under this plan, Oglethorpe contributes 5%, subject to IRS limitations, of each employee's annual compensation. In addition, older employees who participated in the now-terminated defined benefit pension plan received an additional 1% to 2% of compensation through December 31, 2003. There was no additional compensation provided to those older employees in 2005 and 2004. Oglethorpe's contributions to the plan were approximately $758,000 in 2005, $738,000 in 2004 and $696,000 in 2003.

Oglethorpe has a contributory 401(k) plan covering substantially all employees. The employee may contribute, subject to IRS limitations, up to 60% of their 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 the employee's compensation, depending upon the amount and timing of the employee's contribution. Oglethorpe's contributions to the plan were approximately $630,000 in 2005, $603,000 in 2004 and $566,000 in 2003.

Effective January 1, 2005, Oglethorpe merged its money purchase pension plan and its contributory 401(k) plan into one plan, the OPC Retirement Plan. Under the new plan, Oglethorpe will continue to contribute 5%, subject to IRS limitations of each employee's annual compensation and at its discretion, may match the employees' 401(k) contributions, up to as much as three-quarters of the first 6% of the employee's contribution.

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

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 $8,334,000 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 $9,367,000.

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 sell-back adjusted 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.

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

Following the terrorist attacks of September 2001, both ANI and NEIL confirmed that terrorist acts against commercial nuclear power plants would, subject to the normal policy limits, be covered under their insurance. Both companies, however, revised their policy terms on a prospective basis to include an industry aggregate for all "non-certified" terrorists acts, i.e., acts that are not certified acts of terrorism pursuant to the Terrorism Risk Insurance Act of 2002 (TRIA), which was renewed in 2005. The aggregate for all NEIL policies, which applies to non-certified property claims stemming from terrorism within a 12-month duration, is $3.24 billion plus any amounts available through reinsurance or indemnity from an outside source. The non-certified ANI nuclear liability cap is a $300 million shared industry aggregate during the normal ANI policy period.

9. Commitments:

a. Power purchase and sale agreements

Oglethorpe has utilized power marketer arrangements to reduce the cost of power to the Members. Oglethorpe had a power marketer agreement with LEM, for approximately 50% of the load requirements of 37 of the Members that terminated as of December 31, 2004. Oglethorpe also had an additional power marketer agreement with Morgan Stanley, with respect to 50% of the 39 members' then forecasted load requirements and terminated on March 31, 2005. The LEM agreement was based on the actual requirements of the participating Members during the contract term, whereas the Morgan Stanley agreement represented a fixed supply obligation. Generally, these arrangements benefited the Members by limiting the risk of unit non-availability and by providing power needs at a fixed

price. Most of Oglethorpe's generating facilities and power purchase arrangements were available for use by LEM and Morgan Stanley. Oglethorpe continued to be responsible for all of the costs of its system resources, but received revenue from LEM and Morgan Stanley for the use of the resources.

In October 2004, LEM and its affiliates initiated a binding arbitration process to resolve certain issues relating to the LEM agreement. Oglethorpe recorded a $15.0 million reserve at December 31, 2004 for estimated damages payable to LEM. In June 2005, the arbitration panel selected LEM's remedy, which required Oglethorpe to pay LEM approximately $16.0 million. Oglethorpe recorded an additional $1.0 million accrual to purchased power energy costs during the second quarter of 2005 and payment was made to LEM in July 2005. The $16.0 million accrual previously reflected as an unbilled receivable on the balance sheet at December 31, 2004 was billed to the Members in July 2005.

Oglethorpe has entered into a long-term power purchase agreement. As of December 31, 2005, Oglethorpe's minimum purchase commitment under this agreement, 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)

	2006	$	32,759
	2007		28,066
	2008		28,487
	2009		28,914
	2010		29,348
	Thereafter		285,755

Oglethorpe's power purchases from these agreements amounted to approximately $125,628,000 in 2005, $92,039,000 in 2004 and $79,371,000 in 2003.

b. Operating leases

In December 1999 and March 2000, Oglethorpe sold existing coal rail cars and subsequently entered into rental agreements with various terms and expiration dates for the existing and for additional new coal rail cars. On September 23, 2003, Oglethorpe closed a $29 million fifteen-year operating lease related to 523 railcars. The railcars are used to transport coal from the Powder River Basin in Wyoming to Plant Scherer in Georgia. As of December 31, 2005, rental commitments for these operating leases over the next five years and thereafter are as follows:


Year Ending December 31,			(dollars in thousands)

	2006	$	4,806
	2007		4,874
	2008		4,975
	2009		4,926
	2010		5,054
	Thereafter		43,312

Rental expenses incurred under these railcars totaled $5,252,000 in 2005, $5,298,000 in 2004 and $3,610,000 in 2003. The rental expenses for the railcars 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 2005, Oglethorpe sold SO₂ allowances in excess of its needs to various parties and received $83.1 million in proceeds from these sales. Oglethorpe

offset $61.9 million of this income by reducing amounts collected from its Members during 2005. The remaining $21.2 million of income was offset by amortizing in 2005 $21.2 million of deferred asset retirement obligations costs. As a result, there was no net change to net margin.

11. Guarantees:

As of December 31, 2005 and 2004, 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 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

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. 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.

b. Clean Air Act

In December 2002, the Sierra Club, Physicians for Social Responsibility, Georgia Forest Watch and one individual filed suit in Federal Court in Georgia against GPC alleging violations of the Clean Air Act at Plant Wansley. The complaint alleges violations of opacity limits at both the coal-fired units, in which Oglethorpe is a co-owner, and other violations at several of the combined cycle units in which Oglethorpe has no ownership interest. This civil action requests injunctive and declaratory relief, civil penalties, a supplemental environmental project and attorneys' fees. In December 2004, the U.S. District Court for the Northern District of Georgia issued an Order holding GPC liable for certain violations of opacity limits at the coal-fired units. However, in March 2005, the U.S. Court of Appeals for the Eleventh Circuit allowed an immediate appeal of the Court's Order. In March 2006, the Eleventh Circuit reversed the Order, remanding it back to the District Court for trial on the issues. While Oglethorpe believes that Plant Wansley has complied with applicable laws and regulations, resolution of this matter is uncertain at this time, as is Oglethorpe's responsibility, if any, for a share of any penalties or other costs that might be assessed against GPC.

In January 2003, the Sierra Club appealed an unsuccessful challenge to an air operating permit for 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. 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 October 2005, EPA issued an order denying Sierra Club's petition to object to the Chattahoochee facility's air operating permit. In November 2005, EPA issued a subsequent order, correcting the October order and again denying the petition. In January 2006, the Sierra

Club filed an appeal of that order to the U.S. Court of Appeals for the Eleventh Circuit. While Oglethorpe believes that the appeal will not affect facility operations pending further consideration and that a favorable outcome in this matter is likely, an unfavorable ruling could temporarily affect the ability of the facility to continue operations.

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.

The arbitration for the three appeals will be heard by a panel of arbitrators, with the right of appeal first to Monroe County Superior Court and then to the Georgia appellate courts. None of the appeals has been sent to the arbitrators.

Oglethorpe accrues for ad valorem taxes on a monthly basis, which are generally paid in the fourth quarter of the year. For 2005, 2004 and 2003, Oglethorpe increased its accrual by $6,849,000, $4,096,000 and $4,884,000, respectively, for ad valorem taxes relating to Plant Scherer, however, Oglethorpe plans to vigorously oppose these increased assessments through the appeals process described above.

14. Quarterly financial data (unaudited):

Summarized quarterly financial information for 2005 and 2004 is as follows:


			(dollars in thousands)
			First Quarter		Second Quarter		Third Quarter		Fourth Quarter

2005
	Operating revenues	$	297,284	$	279,119	$	322,735	$	270,385
	Operating margin		55,396		45,969		50,976		40,735
	Net margin		11,226		961		5,500		(34	)
2004
	Operating revenues	$	304,844	$	328,416	$	367,489	$	312,023
	Operating margin		56,044		50,501		53,922		37,595
	Net margin		12,718		2,676		4,394		(2,551	)

The negative net margins for the fourth quarters of 2005 and 2004 is the result of reductions to revenue requirements of $5,991,000 and $13,710,000, respectively, approved by Oglethorpe's Board of Directors.

REPORT OF MANAGEMENT

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 is consistent with the financial statements.

Oglethorpe maintains a system of internal control to provide reasonable assurance that assets are safeguarded and that the books and records reflect only authorized transactions. Limitations exist in any system of internal control based upon the recognition that the cost of the system should not exceed its benefits. Oglethorpe believes that its system of internal accounting control, together with the internal auditing function, maintains appropriate cost/benefit relations.

Oglethorpe's system of internal control is evaluated on an ongoing basis by a qualified internal audit staff. The Corporation's independent registered public accounting firm also considers certain elements of the internal control system in order to determine their auditing procedures for the purpose of expressing an opinion on 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.

Thomas A. Smith
President and Chief Executive Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

In our opinion, the accompanying balance sheets, statements of capitalization and the related statements of revenues and expenses, patronage capital and membership fees and accumulated other comprehensive margin and cash flows present fairly, in all material respects, the financial position of Oglethorpe Power Corporation (an Electric Membership Cooperative) at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 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.

PricewaterhouseCoopers LLP
Atlanta, Georgia
March 10, 2006

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

None.

ITEM 9A. CONTROLS AND PROCEDURES

Within 90 days prior to the filing date of this report, Oglethorpe carried out an evaluation, under the supervision and with the participation of its management, including its President and Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of 1934, as amended). Based on this evaluation, the President and Chief Executive Officer and the Chief Financial Officer concluded that Oglethorpe's disclosure controls and procedures are effective.

No significant changes occurred in Oglethorpe's internal controls or in other factors that could significantly affect its internal controls during the quarter ended December 31, 2005.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

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 an Oglethorpe Member located in each of five geographical regions of the State of Georgia. An additional five Member Directors must be a director of an Oglethorpe Member located in each of five geographical regions of the State of Georgia. The eleventh Member Director must be a director of an Oglethorpe Member. An Oglethorpe 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 Senior Officers and Directors of Oglethorpe are as follows:


Name	Age	Position

Thomas A. Smith	51	President and Chief Executive Officer
Michael W. Price	45	Chief Operating Officer
Elizabeth B. Higgins	37	Chief Financial Officer
Jami G. Reusch	43	Vice President, Human Resources
Benny W. Denham	75	Chairman of the Board, Member Director, Southwest Region
J. Sam L. Rabun	74	Vice Chairman of the Board, Member Director, Central Region
Larry N. Chadwick	65	Member Director, Northwest Region
Marshall S. Millwood	56	Member Director, Northeast Region
M. Anthony Ham	54	Member Director, Southeast Region
H.B. Wiley, Jr.	61	Member Director, Statewide
Jeffrey W. Murphy	42	Manager Director, Northeast Region
Gary A. Miller	45	Manager Director, Northwest Region
C. Hill Bentley	58	Manager Director, Central Region
Gary W. Wyatt	53	Manager Director, Southwest Region
Robert E. Rentfrow	51	Member Director, Southeast Region
Wm. Ronald Duffey	64	Outside Director
John S. Ranson	76	Outside Director

Oglethorpe has an Audit Committee, whose members are Wm. Ronald Duffey, Jeffrey W. Murphy, Marshall S. Millwood, Robert E. Rentfrow 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.

Oglethorpe has adopted a Code of Ethics that applies to the Senior Officers and the Controller of Oglethorpe.

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, the Georgia Chamber of Commerce, and En-Touch Systems, Inc. Mr. Smith is also a member of the NERC Stakeholders

Committee and a member of the Advisory Board of Mid-South Telecommunications, Inc.

Michael W. Price is the Chief Operating Officer of Oglethorpe and has served in that office since February 1, 2000. Mr. Price served 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 served 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 TVA from 1983 to 1986. Mr. Price has a Bachelor of Science degree in Electrical Engineering from Auburn University. Mr. Price is a Director of Southeastern Federal Power Customers, Inc., 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 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 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.

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.

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 2007. Mr. Denham has been co-owner of Denham Farms in Turner County, Georgia since 1980. Mr. Denham is on the Board of Directors of Community National Bank of Ashburn, Georgia, and 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 is also the Chairman of the Compensation Committee. He has been the owner and operator of a farm in Jefferson County, Georgia since 1979. He is also a 50% owner of R&R Livestock Farms, Inc. He has served on the Board of Directors of Oglethorpe since March 1993. His present term will expire in March 2007. Mr. Rabun served as the President of the Board of Jefferson EMC from 1993 to 1996, was employed as General Manager from 1974 to 1979 and as Office Manager and Accountant from 1970 to 1974. 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 is also a member of the Compensation Committee. He has served on the Board of Directors of Oglethorpe since July 1989. His present term will expire in March 2008. 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 in March 2003, and his term will expire in March 2006. 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 in March 2008. Mr. Ham is the Clerk of the Superior and Juvenile Courts in Brantley County, Georgia. He is a Director of Okefenoke Rural EMC.

H.B. Wiley, Jr. is the Member Director elected statewide. He became a member of the Board of Directors in March 2003 and his term will expire in March 2006. Mr. Wiley previously served as a member of the Board of Directors from July 1994 until March 1997. He is also a member of the Audit Committee. Mr. Wiley has been an associate broker in real estate since 1994. Prior to that 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 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 Board of Directors of Oglethorpe in March 2004, and his term will expire in March 2006. 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. He is also a member of the Compensation Committee. Mr. Miller became a member of the Board of Directors of Oglethorpe in March 2004, and his term will expire in March 2006. 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 the past-President of the Georgia Rural Electric Managers Association. He is also a past Chairman of the Douglas County Chamber of Commerce. 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 term will expire in March 2007. 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, and a member of the Bibb County Chamber of Commerce and Georgia Chamber of Commerce. He is the Vice President of the Georgia Rural Electric Managers Association and on the Business Advisory Council for Georgia College and State University.

Gary W. Wyatt is the Manager Director from the Southwest Region. He became a member of the Board of Directors of Oglethorpe in March 2004, and his term will expire in March 2007. He is the President and CEO of Pataula EMC. He is a past Chairman of the Georgia Rural Electric Managers Association. He is a past President of the Randolph-Cuthbert Chamber of Commerce. Mr. Wyatt is a graduate of Darton College.

Robert E. Rentfrow is the Manager Director from the Southeast Region. Mr. Rentfrow became a Member of the Board of Directors of Oglethorpe in June 2002. Mr. Rentfrow is a member of the Audit Committee. Mr. Rentfrow's term on the Board of Directors of Oglethorpe will expire in March 2008. Mr. Rentfrow has been the President and Chief Executive Officer of Satilla Rural EMC since 1996 and has been associated with EMCs in Georgia for the past 21 years. Mr. Rentfrow serves as Director on the Governor's Workforce Investment Board and is a member of the Southeast Georgia Financial Board. Mr. Rentfrow also serves as Chairman of the Bacon County Industrial Building Authority and is a member of the Waycross College Board of Trustees. Mr. Rentfrow is a graduate of Southern Technical Institute and Georgia Southern College.

Wm. Ronald Duffey is an Outside Director. He has served on the Board of Directors of Oglethorpe since March 1997. He is the Chairman of the Audit Committee. His term will expire in March 2006. 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 Fayette

Community 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 term will expire in March 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.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth, for Oglethorpe's President and Chief Executive Officer and for the four other executive officers, all compensation paid or accrued for services rendered in all capacities during the years ended December 31, 2005, 2004 and 2003.


		Annual Compensation
Name and Principal Position	Year		Salary		Bonus		All Other Compensation ⁽¹⁾

Thomas A. Smith President and Chief Executive Officer	2005 2004 2003	$	395,833 360,833 325,000	$	130,860 120,540 91,910	$	21,192 120,638 169,810
Michael W. Price Chief Operating Officer	2005 2004 2003		215,608 206,995 206,669		75,724 71,859 56,198		20,635 19,912 19,438
Elizabeth B. Higgins Chief Financial Officer	2005 2004 2003		208,667 190,557 164,683		73,282 69,569 42,067		20,007 44,661 73,404
W. Clayton Robbins Senior Vice President, Chief Administrative Officer	2005 2004 2003		188,083 182,470 182,640		57,709 55,298 43,878		21,809 20,936 21,921
Jami G. Reusch Vice President, Human Resources ⁽²⁾	2005 2004		124,583 105,458		38,626 34,655		14,104 11,163

(1): Figures for 2005 consist of contributions made by Oglethorpe under the 401(k) Retirement Savings Plan on behalf of Mr. Smith, Mr. Price, Mr. Robbins, Ms. Higgins and Ms. Reusch of $9,450, $9,450, $9,534, $9,111 and $5,606, respectively; contributions under Oglethorpe's Money Purchase Pension Plan on behalf of Mr. Smith, Mr. Price, Mr. Robbins, Ms. Higgins and Ms. Reusch of $10,500, $10,500, $10594, $10,500 and $7,962, respectively; and insurance premiums paid on term life insurance on behalf of Mr. Smith, Mr. Price, Mr. Robbins, Ms. Higgins and Ms. Reusch of $1,242, $685, $1,681, $396 and $536, respectively.
(2): Ms. Reusch became an executive officer of Oglethorpe in 2004. The information provided includes all compensation paid to her in 2004.

Compensation of Directors

Oglethorpe pays its Outside Directors a fee of $5,500 per Board meeting for four meetings in a year; a fee of $1,000 per Board meeting will be paid for the remaining other Board meetings in a year. Outside Directors are also paid $1,000 per day for attending committee meetings, annual meetings of the Members or other official business of Oglethorpe. Member Directors are paid a fee of $1,000 per Board meeting and $600 per day for attending committee meetings, annual meetings of the Members or other official business of Oglethorpe. In addition, Oglethorpe reimburses all Directors for out-of-pocket expenses incurred in attending a meeting. All Directors are paid $50 per day when participating in meetings by conference call. The Chairman of the Board is paid an additional 20% of his Director's fee per Board meeting for time involved in preparing for the meetings. The Audit Committee Financial Expert is paid an additional $400 per Audit Committee meeting for the time involved in fulfilling that role.

Employment Contracts

Oglethorpe entered into an Employment Agreement with Thomas A. Smith, Oglethorpe's President and Chief Executive Officer, effective March 15, 2002. The initial term of the agreement extended through December 31, 2004, and automatically renews for successive one-year periods unless either party gives notice of termination 24 months prior to the expiration of the agreement or any extension of the agreement. The agreement has automatically renewed until December 31, 2007. Mr. Smith's minimum base salary is $325,000 per year, and is annually adjusted by the Board of Directors of Oglethorpe. In addition, Mr. Smith has opportunities for variable pay for accomplishing goals set by Oglethorpe's Board of Directors each year.

Upon the occurrence of any of the following events, Mr. Smith will be entitled to a lump-sum severance payment: (1) Oglethorpe terminates Mr. Smith's employment without cause; (2) Mr. Smith resigns within 180 days of a material reduction or alteration of his title or responsibilities or a change in the location of Mr. Smith's principal office by more than 50 miles;

(3) Oglethorpe is sold or Oglethorpe sells essentially all of its assets or control of its assets, and the sale results in a termination of Mr. Smith's employment as President and Chief Executive Officer of Oglethorpe or a material reduction of his title or responsibilities; or (4) an event of default under Oglethorpe's RUS loan contract occurs and is continuing and RUS requests that Oglethorpe terminate Mr. Smith. 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) plus the cost of providing all health and dental insurance for the longer of one year or the remaining term of the agreement.

Oglethorpe has also entered into Employment Agreements with Michael W. Price, Elizabeth B. Higgins and Jami G. Reusch, Oglethorpe's Chief Operating Officer, Chief Financial Officer and Vice President, Human Resources, respectively. Each agreement automatically renews for successive one-year periods ending each December 31 unless either party gives notice of termination 13 months prior to the expiration of any extension of the Agreement. Minimum annual base salaries are $172,000 for Mr. Price, $165,000 for Ms. Higgins and $115,000 for Ms. Reusch. Salaries are annually adjusted by the Board of Directors of Oglethorpe. Each executive has opportunities for variable pay for accomplishing goals set by Oglethorpe's Board of Directors each year.

Under each Employment Agreement, the executive will be entitled to a lump-sum severance payment if Oglethorpe terminates the executive without cause or if the executive resigns after (1) a demotion or a material reduction or alteration of the executive's title or responsibilities, (2) a reduction of the executive's base salary or (3) a change in the location of the executive's principal office by more than 50 miles. The severance payment will equal the executive's base salary for one year, plus the equivalent of six months' medical allowance.

Compensation Committee Interlocks and Insider Participation

J. Sam L. Rabun, John S. Ranson, Gary A. Miller and Larry N. Chadwick served as members of the Oglethorpe Power Corporation Compensation Committee in 2004. J. Sam L. Rabun served as the Vice Chairman of the Board in 2004.

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 to Oglethorpe under the Wholesale Power Contract accounted for approximately 7% of Oglethorpe's total revenues and 45% of GreyStone Power Corporation's total revenues in 2005.

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

Not applicable.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Robert E. Rentfrow is 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 payments to Oglethorpe under the Wholesale Power Contract accounted for approximately 2% of Oglethorpe's total revenues and 33% of Satilla Rural EMC's total revenues in 2005.

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 to Oglethorpe under the Wholesale Power Contract accounted for approximately 2% of Oglethorpe's total revenues and 43% of Hart EMC's total revenues in 2005.

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 to Oglethorpe under the Wholesale Power Contract accounted for approximately 1% of Oglethorpe's total revenues and 45% of Tri-County EMC's total revenues in 2005.

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 to Oglethorpe under the Wholesale Power Contract accounted for approximately less than 1% of Oglethorpe's total revenues and 37% of Pataula EMC's total revenues in 2005.

Herbert J. Short began serving as Oglethorpe's General Counsel in August 2005. Mr. Short is a partner with Sutherland Asbill & Brennan LLP. Sutherland Asbill & Brennan LLP provides legal services to Oglethorpe on a regular basis.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

For 2005 and 2004, fees for services provided by Oglethorpe's principal accountants, PricewaterhouseCoopers LLP were as follows:


		(dollars in thousands)
		2005		2004

Audit Fees ⁽¹⁾	$	232	$	209
Tax Fees ⁽²⁾		42		24
Audit-Related Fees ⁽³⁾		52		–
All Other Fees		–		–

Total	$	326	$	233

(1): Audit of annual financial statements and review of financial statements included in SEC filings.
(2): Professional tax services including tax consultation and tax return preparation.
(3): Audited related services rendered in connection with financing and consultations regarding the implementation of Sarbanes-Oxley compliance.

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 PricewaterhouseCoopers LLP, in 2005 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")
	Statements of Revenues and Expenses, For the Years Ended December 31, 2005, 2004 and 2003	49
	Balance Sheets, As of December 31, 2005 and 2004	50
	Statements of Capitalization, As of December 31, 2005 and 2004	52
	Statements of Cash Flows, For the Years Ended December 31, 2005, 2004 and 2003	53
	Statements of Patronage Capital and Membership Fees And Accumulated Other Comprehensive Margin For the Years Ended December 31, 2005, 2004 and 2003	54
	Notes to Financial Statements	55
	Report of Management	73
	Report of Independent Registered Public Accounting Firm	73
(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.)

*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	–	Amended and Restated Loan Contract, dated as of May 21, 2003, 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-K for the fiscal year ended December 31, 2003, 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.)

*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 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.)
*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(dd) to the Registrant's Form 10-K for the fiscal year ended December 31, 2004, File No. 33-7591.)
*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(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.

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.
*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.
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 (Adustable 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.
*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.
*4.15	–	Exchange and Registration Rights Agreement, dated December 17, 1997, by and among Oglethorpe, OPC Scherer 1997 Funding Corporation A, and Goldman, Sachs & Co. as representative of the purchasers identified therein. (Filed as Exhibit 4.15 to the Registrant's Form S-4 Registration Statement, File No. 333-42759.)
*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.)
*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.)
*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.)
*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	–	Alvin W. Vogtle Nuclear 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 August 27, 1976. (Filed as Exhibit 10.7.2 to the Registrant's Form S-1 Registration Statement, 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.)
*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, 2004, 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.)
*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	–	Amended and Restated Nuclear Managing Board Agreement among Georgia Power Company, Oglethorpe Power Corporation, Municipal Electric Authority of Georgia and City of Dalton, Georgia dated as of July 1, 1993. (Filed as Exhibit 10.36 to the Registrant's 10-Q for the quarterly period ended September 30, 1993, 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.)
*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.)
*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	–	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.)
*10.17.2	–	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 March 15, 2002, between Oglethorpe and Thomas A. Smith. (Filed as Exhibit 10.25 to the Registrant's Form 10-K for the fiscal year ended December 31, 2001, File No. 33-7591.)
*10.20⁽³⁾	–	Employment Agreement, dated July 25, 2000, between Oglethorpe and Michael W. Price. (Filed as Exhibit 10.26 to the Registrant's Form 10-K for the fiscal year ended December 31, 2001, File No. 33-7591.)

*10.21⁽³⁾	–	Employment Agreement, dated August 7, 2000, between Oglethorpe and Elizabeth Higgins. (Filed as Exhibit 10.29 to the Registrant's Form 10-Q for the quarterly period ended June 30, 2000, File No. 33-7591.)
*10.22	–	Employment Agreement, dated as of November 12, 2004, 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, 2004, File No. 33-7591.)
*10.23	–	Oglethorpe Power Corporation Executive Supplemental Retirement Plan, dated March 15, 2002. (Filed as Exhibit 10.29 to the Registrant's Form 10-Q for the quarterly period ended March 31, 2002, File No. 33-7591.)
*10.24	–	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.)
*10.25	–	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, 2004, 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.

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 30^th day of March, 2006.

		OGLETHORPE POWER CORPORATION (AN ELECTRIC MEMBERSHIP CORPORATION)
		By:		/s/ THOMAS A. SMITH THOMAS 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. SMITH THOMAS A. SMITH	President and Chief Executive Officer (Principal Executive Officer)	March 30, 2006
/s/ ELIZABETH B. HIGGINS ELIZABETH B. HIGGINS	Chief Financial Officer (Principal Financial Officer)	March 30, 2006
/s/ MARK CHESLA MARK CHESLA	Vice President, Controller (Chief Accounting Officer)	March 30, 2006
/s/ C. HILL BENTLEY C. HILL BENTLEY	Director	March 30, 2006
/s/ LARRY N. CHADWICK LARRY N. CHADWICK	Director	March 30, 2006
/s/ BENNY W. DENHAM BENNY W. DENHAM	Director	March 30, 2006
/s/ WM. RONALD DUFFEY WM. RONALD DUFFEY	Director	March 30, 2006
/s/ M. ANTHONY HAM M. ANTHONY HAM	Director	March 30, 2006

/s/ GARY A. MILLER GARY A. MILLER	Director	March 30, 2006
/s/ MARSHALL MILLWOOD MARSHALL MILLWOOD	Director	March 30, 2006
/s/ JEFFREY W. MURPHY JEFFREY W. MURPHY	Director	March 30, 2006
/s/ J. SAM L. RABUN J. SAM L. RABUN	Director	March 30, 2006
/s/ JOHN S. RANSON JOHN S. RANSON	Director	March 30, 2006
/s/ ROBERT E. RENTFROW ROBERT E. RENTFROW	Director	March 30, 2006
/s/ H. B. WILEY, JR. H. B. WILEY, JR.	Director	March 30, 2006
/s/ GARY W. WYATT GARY W. WYATT	Director	March 30, 2006

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.

100

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OGLETHORPE POWER CORPORATION 2005 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
STATEMENTS OF REVENUES AND EXPENSES For the years ended December 31, 2005, 2004 and 2003
BALANCE SHEETS December 31, 2005 and 2004
BALANCE SHEETS
STATEMENTS OF CAPITALIZATION December 31, 2005 and 2004
STATEMENTS OF CASH FLOWS For the years ended December 31, 2005, 2004 and 2003
STATEMENTS OF PATRONAGE CAPITAL AND MEMBERSHIP FEES AND ACCUMULATED OTHER COMPREHENSIVE MARGIN For the years ended December 31, 2005, 2004 and 2003
NOTES TO FINANCIAL STATEMENTS For the years ended December 31, 2005, 2004 and 2003
PART III
PART IV
SIGNATURES

Positive
Negative
Uncertain
Constraining
Legalese
Litigous
Readability	8th grade Avg

Oglethorpe Ratings

Moody's

Senior secured debt

Short-term debt (commercial paper)