Offer To Exchange
$350,000,000
Registered 6.10% First Mortgage Bonds, Series 2009 A due 2019
for any and all
Unregistered 6.10% First Mortgage Bonds, Series 2009 A due 2019

We are offering to exchange up to $350,000,000 in aggregate principal amount of our registered 6.10% First Mortgage Bonds, Series 2009 A due 2019, which we refer to as the exchange bonds, for $350,000,000 in aggregate principal amount of our outstanding unregistered 6.10% First Mortgage Bonds, Series 2009 A due 2019, which we refer to as the original bonds. The exchange bonds will be issued under the same indenture as the original bonds.

All untendered original bonds will remain outstanding and continue to be subject to the restrictions on transfer set forth in the original bonds and in the indenture governing the original bonds. In general, the original bonds may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offer, we do not currently anticipate that we will register the original bonds under the Securities Act.

Each broker-dealer that receives exchange bonds for its own account in this exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of those exchange bonds. The related letter of transmittal that is delivered with this prospectus states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange bonds received in exchange for original bonds the broker-dealer acquired as a result of market-making activities or trading activities. We have agreed that we will make this prospectus available to any broker-dealer for use in connection with any such resale for a period of 180 days following the expiration date of the exchange offer. See "PLAN OF DISTRIBUTION" beginning on page 128 of this prospectus.

Each holder of original bonds wishing to accept this exchange offer must effect a tender of original bonds by book-entry transfer into the exchange agent's account at The Depository Trust Company (DTC). All deliveries are at the risk of the holder. You can find detailed instructions concerning delivery in the section of this prospectus entitled "THE EXCHANGE OFFER" beginning on page 101.

See "RISK FACTORS" beginning on page 12 for a discussion of factors that you should consider before participating in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.

YOU SHOULD READ THIS ENTIRE DOCUMENT AND THE ACCOMPANYING LETTER OF TRANSMITTAL AND RELATED DOCUMENTS AND ANY AMENDMENTS OR SUPPLEMENTS CAREFULLY BEFORE MAKING YOUR DECISION TO PARTICIPATE IN THIS EXCHANGE OFFER.

You should rely only on the information contained in this prospectus. We have not authorized anyone to provide you with additional or different information. This prospectus may be used only for the purposes for which it has been published, and no person has been authorized to give any information not contained in this prospectus. If you receive any other information, you should not rely on it. You should assume that the information contained in this prospectus is accurate only as of the date on the front cover of this prospectus. No offer of these securities is being made in any jurisdiction where such offer is prohibited.


		Page
PROSPECTUS SUMMARY		1
RISK FACTORS		12
FORWARD-LOOKING STATEMENTS		20
USE OF PROCEEDS		22
SELECTED FINANCIAL DATA		23
OUR BUSINESS		24
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		53
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		79
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE		82
EXECUTIVE COMPENSATION		88
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS		98
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE		99
THE EXCHANGE OFFER		101
THE EXCHANGE BONDS		112
SUMMARY OF THE INDENTURE		116
SUMMARY OF MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES		125
PLAN OF DISTRIBUTION		128
LEGAL MATTERS		128
EXPERTS		129
AVAILABLE INFORMATION		129
INDEX TO FINANCIAL STATEMENTS		F-1
APPENDIX A—MEMBERS' FINANCIAL AND STATISTICAL INFORMATION		A-1

This summary highlights selected information appearing elsewhere in this prospectus. This summary is not complete and does not contain all of the information that you should consider before participating in the exchange offer. You should carefully read the entire prospectus, including the information set forth in the sections entitled "RISK FACTORS," "SELECTED FINANCIAL DATA," and the other financial data and related notes included elsewhere in this prospectus. Unless the context otherwise requires, references in this prospectus to Oglethorpe, us, we, or our, refer to Oglethorpe Power Corporation (An Electric Membership Corporation), together with our consolidated subsidiaries.


Power Supply Business		We provide wholesale electric service to our members, each a Georgia electric membership corporation, for a substantial portion of their requirements from a combination of our generation assets and purchased power. We provide this service pursuant to long-term, take-or-pay Amended and Restated Wholesale Power Contracts, each dated January 1, 2003, and amended as of June 1, 2005. See "OUR BUSINESS—Wholesale Power Contracts." The wholesale power contracts obligate our members jointly and severally to pay rates sufficient to recover all the costs of owning and operating our power supply business.
		We have undivided interests in 27 generating units. These units provide us with a total of 5,244 megawatts of nameplate capacity, consisting of 1,501 megawatts of coal-fired capacity, 1,185 megawatts of nuclear-fueled capacity, 632 megawatts of pumped storage hydroelectric capacity, 1,911 megawatts of gas-fired capacity (206 megawatts of which is capable of running on oil) and 15 megawatts of oil-fired combustion turbine capacity. We also purchase a total of approximately 300 megawatts of power pursuant to a long-term power purchase agreement.
Certain Agreements with Our Members		We have 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 of each of our 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. We are obligated to use our reasonable best efforts to operate, maintain and manage our resources in accordance with prudent utility practices.
		We have assigned fixed percentage capacity costs responsibilities to our members for all of our generation and purchased power resources. For any future resource, we will assign fixed percentage capacity costs responsibilities only to members choosing to participate in that resource. The wholesale power contracts provide that each member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for any approved future resources, whether or not this member has elected to participate in this future resource. For resources so approved in which less than all members participate, costs are shared first among the participating members, and if all participating members default, each non-participating member is expressly obligated to pay a proportionate share of the default.


		To acquire future resources, we are required to obtain the approval of 75% of the members of our board of directors, 75% of our members, and members representing 75% of our patronage capital. We can make certain resource modifications if approved by more than 50% of the members of our board of directors and 50% of our members.
		Under the wholesale power contracts, we are not obligated to provide all of our members' capacity and energy requirements. Individual members must satisfy all of their requirements above their purchase obligations from us from other suppliers, unless we and our members agree that we will supply additional capacity and associated energy, subject to the approval requirements described above. In 2008, we supplied energy sufficient to meet approximately 65% of our members' retail energy requirements.
		Under the wholesale power contracts, each member must establish rates and conduct its business in a manner that will enable the member to pay:
		•		to us, when due, all amounts payable by the member under its wholesale power contract, and
		•		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.
		In 2003, we entered into an agreement with our members that requires member approval for us to undertake certain activities. It does not limit our ability to own, manage, control and operate our resources or perform our functions under the wholesale power contracts.
		In this regard, we may not provide services unrelated to our resources or our functions under the wholesale power contracts if these services would require us to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of the members of our board of directors, 75% of our members, and members representing 75% of our patronage capital. We may provide any other service to a member so long as:
		•		doing so would not create a conflict of interest with respect to other members,
		•		the service is being provided to all members, or
		•		the service has received the three-part 75% approvals described above.


Electric Rates		Each member is required to pay us for capacity and energy furnished under its wholesale power contract in accordance with rates we establish. We review our rates in intervals we deem appropriate but we are required to do so at least once every year. We are required to revise our rates as necessary so that the revenues derived from our rates, together with our revenues from all other sources, will be sufficient to pay all costs of our system, to provide for reasonable reserves and to meet all financial requirements.
		The formulary rate we established in the rate schedule to the wholesale power contracts employs a rate methodology under which all categories of costs are specifically separated as components of the formula to determine our revenue requirements. The formulary rate schedule also implements the responsibility for fixed costs assigned to each member. The monthly charges for capacity and other non-energy charges are based on our annual budget. Energy charges reflect the pass-through of actual energy costs, including fuel costs, variable operations and maintenance costs and purchased energy costs.
		Adjustments to our rates to reflect changes in our budgets are generally not subject to approval by any third parties. However, changes to the formulary rate schedule under the wholesale power contracts are generally subject to approval by the Rural Utilities Services in accordance with the terms of our loan agreement with the Rural Utilities Service. The Rural Utilities Service is an agency of the United States Department of Agriculture that administers federal loan programs that historically have provided the principal sources of financing for electric cooperatives. Our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.
Our Members and their Power Supply Resources		Our members, listed on page 34 of this prospectus, include 38 of the 42 electric distribution cooperatives in the State of Georgia.
		Our members service approximately 1.7 million electric consumers (meters), representing approximately 4.1 million people. Our 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 our members in 2008 amounted to approximately 34 million megawatt-hours, with approximately 68% to residential consumers, 29% to commercial and industrial consumers and 3% to other consumers. Our members are the principal suppliers for the power needs of rural Georgia.


THE EXCHANGE OFFER
General	We are conducting the exchange offer to satisfy our obligation under the registration rights agreement entered into in connection with the issuance of the original bonds on February 19, 2009.
The Exchange Offer	We are offering to exchange $350,000,000 aggregate principal amount of 6.10% First Mortgage Bonds, Series 2009 A due 2019 that have been registered under the Securities Act for any and all of our outstanding 6.10% First Mortgage Bonds, Series 2009 A due 2019.
	The exchange bonds will be issued in $1,000 denominations or any integral multiple of $1,000.
Resale	Based on an interpretation by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the exchange bonds issued pursuant to the exchange offer in exchange for the original bonds may be offered for resale, resold and otherwise transferred by you (unless you are our "affiliate" within the meaning of Rule 405 under the Securities Act) without compliance with the registration and prospectus delivery provisions of the Securities Act, provided that:
	•	you are acquiring the exchange bonds in the ordinary course of your business; and
	•	you have not engaged in, do not intend to engage in, and have no arrangement or understanding with any person to participate in, a distribution of the exchange bonds.
	If you are a broker-dealer and receive exchange bonds for your own account in exchange for original bonds that you acquired as a result of market making activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the exchange bonds and that you are not our affiliate and did not purchase your original bonds from us or any of our affiliates. See "PLAN OF DISTRIBUTION."
	Any holder of original bonds who:
	•	is our affiliate;
	•	does not acquire exchange bonds in the ordinary course of its business; or
	•	tenders its original bonds in the exchange offer with the intention to participate, or for the purpose of participating, in a distribution of the exchange bonds


	cannot rely on the position of the staff of the SEC enunciated in Morgan Stanley & Co. Incorporated (available June 5, 1991) and Exxon Capital Holdings Corporation (available May 13, 1988), as interpreted in Shearman & Sterling (available July 2, 1993), or similar no action letters and must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange bonds, unless otherwise exempt from these requirements.
	Our belief that the exchange bonds may be offered for resale without compliance with the registration or prospectus delivery requirements of the Securities Act is based on interpretations of the SEC contained in no-action letters to other issuers in exchange offers like ours. We cannot guarantee that the SEC would make a similar decision about our exchange offer. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any exchange bond without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from these requirements, you could incur liability under the Securities Act. We will not indemnify you for this liability.
Expiration Date	The exchange offer will expire at 5:00 p.m., New York City time, on July 9, 2009, unless extended by us. We do not currently intend to extend the expiration date.
Withdrawal Rights	You may withdraw the tender of your original bonds at any time prior to the expiration of the exchange offer. We will return to you any of your original bonds that are not accepted for any reason for exchange, without expense to you, promptly after the expiration or termination of the exchange offer.
Conditions to the Exchange Offer	The exchange offer is subject to customary conditions. We reserve the right to waive any defects, irregularities or conditions to exchange as to particular original bonds. See "THE EXCHANGE OFFER—Conditions to the Exchange Offer."
Procedures for Tendering Original Bonds	If you wish to participate in the exchange offer, you must either:
	•	complete, sign and date the accompanying letter of transmittal, or a facsimile of the letter of transmittal, in accordance with the instructions contained in this prospectus and the letter of transmittal, and mail or deliver the letter of transmittal or facsimile of the letter of transmittal to the exchange agent at the address provided on the cover page of the letter of transmittal; or


	•	if you hold original bonds through DTC, comply with DTC's automated tender offer program procedures described in this prospectus, by which you agree to be bound by the letter of transmittal.
	By signing, or agreeing to be bound by, the letter of transmittal, you will represent to us that, among other things:
	•	you are not our "affiliate" within the meaning of Rule 405 under the Securities Act;
	•	you have no arrangement or understanding with any person to participate in the distribution of the exchange bonds;
	•	you are not engaged in, and do not intend to engage in, a distribution of the exchange bonds;
	•	you are acquiring the exchange bonds in the ordinary course of your business;
	•	if you are a broker-dealer, that you did not purchase your original bonds from us or any of our affiliates; and
	•	if you are a broker-dealer, that will receive exchange bonds for your own account in exchange for the original bonds that were acquired as a result of market-making activities, you will deliver a prospectus, as required by law, in connection with any resale of such exchange bonds.
Special Procedures for Beneficial Owners	If you are the beneficial owner of original bonds that are registered in the name of a broker, dealer, commercial bank, trust company or other nominee, and you wish to tender those original bonds in the exchange offer, you should contact the registered holder promptly and instruct the registered holder to tender those original bonds on your behalf. If you wish to tender on your own behalf, you must, prior to completing and executing the letter of transmittal and delivering your original bonds, either make appropriate arrangements to register ownership of the original bonds in your name or obtain a properly completed bond power from the registered holder. The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration date.


Guaranteed Delivery Procedures		If you wish to tender your original bonds and your original bonds are not immediately available, or you cannot deliver your original bonds, the letter of transmittal or any other required documents, or you cannot comply with the procedures under DTC's automated tender offer program for transfer of book-entry interests prior to the expiration date, you must tender your original bonds according to the guaranteed delivery procedures set forth in this prospectus under "THE EXCHANGE OFFER—Guaranteed Delivery Procedures."
Effect on Holders of Original Bonds		As a result of the making of, and upon acceptance for exchange of all validly tendered original bonds pursuant to the terms of the exchange offer, we will have fulfilled a covenant under the registration rights agreement. Accordingly, there will be no increase in the applicable interest rate on the original bonds under the circumstances described in the registration rights agreement. If you do not tender your original bonds in the exchange offer, you will continue to be entitled to all of the rights and limitations applicable to the original bonds as set forth in the indenture described below, except we will not have any further obligation to you to provide for the exchange and registration of untendered original bonds under the registration rights agreement. To the extent that original bonds are tendered and accepted in the exchange offer, the trading market for original bonds that are not so tendered and accepted could be adversely affected.
Consequences of Failure to Exchange		All untendered original bonds will continue to be subject to the restrictions on transfer set forth in the original bonds. In general, the original bonds may not be offered or sold, unless registered under the Securities Act, except pursuant to an exemption from, or in a transaction not subject to, the Securities Act and applicable state securities laws. Other than in connection with the exchange offer, we do not intend to register the original bonds under the Securities Act.
Certain U.S. Federal Income Tax Consequences		The exchange of original bonds for exchange bonds in the exchange offer will not be a taxable event for U.S. federal income tax purposes. See "SUMMARY OF MATERIAL UNITED STATES FEDERAL INCOME TAX CONSEQUENCES."
Use of Proceeds		We will not receive any cash proceeds from the issuance of the exchange bonds in the exchange offer. See "USE OF PROCEEDS."

The summary below describes the principal terms of the exchange bonds. Certain of the terms and conditions described below are subject to important limitations and exceptions. "THE EXCHANGE BONDS" section of this prospectus contains more detailed descriptions of the terms and conditions of the original bonds and the exchange bonds. The exchange bonds will have terms substantially identical to the original bonds, except that the exchange bonds will not contain terms with respect to transfer restrictions, registration rights and additional interest for failure to observe certain obligations in the registration rights agreement.


Risk Factors		You should consider carefully all of the information set forth in this prospectus prior to exchanging your original bonds. In particular, we urge you to consider carefully the factors set forth under the heading "RISK FACTORS."
THE INDENTURE
Security for the Exchange Bonds		The exchange bonds will be secured equally and ratably with all our other obligations issued under the indenture by a first mortgage lien on substantially all of our owned tangible and certain of our intangible assets, including our electric generating plants and facilities, certain of our contracts for the purchase, sale or transmission of electricity or pooling or other power supply arrangements of more than one year in duration and certain of our contracts that relate to the ownership, operation or maintenance of electric generation, transmission or distribution facilities owned by us, but excluding certain exceptions set forth in the indenture. The indenture contains provisions subjecting all of our after-acquired property, other than certain exceptions set forth in the indenture, to the lien of the indenture. See "SUMMARY OF THE INDENTURE."
Rate Covenant		The indenture obligates us to establish and collect rates, rents, charges, fees and other compensation, collectively, the rates, for the use or the sale of the output, capacity or service of our properties that, subject to any necessary regulatory approvals, are reasonably expected, together with our other revenues, to yield a margins for interest ratio equal to at least 1.10 for each fiscal year. See "SUMMARY OF THE INDENTURE—Covenants" for a description of the margins for interest ratio. To enhance financial coverage during an anticipated period of generation facility construction, our board of directors approved a budget for 2009 to achieve a 1.12 margins for interest ratio. Our board of directors will evaluate coverage ratios throughout the period of anticipated construction and may choose to increase or decrease the margins for interest ratio in the future.
Additional Obligations		As long as we are in compliance with the minimum margins for interest ratio required by the indenture, we may issue additional indebtedness or other obligations under the indenture. The amount of obligations we may issue is based on the bondable value of specified property additions and retirements we have made, the aggregate principal amount of indenture obligations we have retired or defeased, and deposits of cash and certain securities we have made with the trustee. See "SUMMARY OF THE INDENTURE—Additional Indenture Obligations."

You should carefully consider the risk factors set forth below as well as the other information contained in this prospectus before deciding to tender your original bonds in the exchange offer. Any of the following risks could materially and adversely affect our business, financial condition, operating results or cash flow; however, the following risks are not our only risks. Additional risks and uncertainties not currently known to us or those we currently view to be immaterial may also materially and adversely affect our business, financial condition, results of operations or cash flow. If any known or unknown risk materially affects our business, financial condition, results of operations or cash flow, the trading price of the exchange bonds could decline or we may not be able to make payments of interest and principal on the exchange bonds, and you may lose all or part of your original investment.

If you do not properly tender your original bonds for exchange bonds, you will continue to hold unregistered bonds which are subject to transfer restrictions.

We will only issue exchange bonds in exchange for original bonds that are received by the exchange agent in a timely manner together will all required documents. Therefore, you should allow sufficient time to ensure timely delivery of the original bonds, and you should carefully follow the instructions on how to tender your original bonds set forth under "THE EXCHANGE OFFER—Procedures for Tendering Original Bonds" and in the letter of transmittal that you received with this prospectus. Neither we nor the exchange agent are required to tell you of any defects or irregularities with respect to your tender of the original bonds.

If you do not tender your original bonds or if we do not accept your original bonds because you did not tender your original bonds properly, you will continue to hold original bonds. Any original bonds that remain outstanding after the expiration of the exchange offer will continue to be subject to restrictions on their transfer in accordance with the Securities Act. After the expiration of this exchange offer, holders of the original bonds will not have any further rights to have their original bonds registered under the Securities Act. In addition, if you tender your original bonds for the purpose of participating in a distribution of the exchange bonds, you will be required to comply with the registration and prospectus delivery requirements of the Securities Act in connection with any resale of the exchange bonds. If you continue to hold any original bonds after this exchange offer is completed, you may have difficulty selling them because of the restrictions on transfer and because we expect that there will be fewer original bonds outstanding, which would result in an illiquid trading market for the original bonds. The value of the original bonds could be adversely affected at the conclusion of this exchange offer. There may be no market for the remaining original bonds which means you may be unable to sell any remaining original bonds.

If an active trading market does not develop for the exchange bonds, you may be unable to sell the exchange bonds or to sell them at a price you deem sufficient.

The exchange bonds will be new securities for which there is no established trading market. We do not intend to apply for listing of the exchange bonds on any national securities exchange or to arrange for the exchange bonds to be quoted on any automated quotation system. As a result, we cannot provide any assurance as to:

Even if a trading market develops, the exchange bonds may trade at higher or lower prices than their principal amount or purchase price, depending on many factors, including:

If a market for the exchange bonds does not develop, purchasers may be unable to resell the exchange bonds for an extended period of time. Consequently, a holder of exchange bonds may not be able to liquidate its investment readily, and the exchange bonds may not be readily accepted as collateral for loans. In addition, market-making activities will be subject to restrictions of the Securities Act and the Securities Exchange Act of 1934.

In addition, if a large number of the holders of original bonds do not tender original bonds or tender original bonds improperly, the limited amount of exchange bonds that would be issued or outstanding after we complete this exchange offer would adversely affect the development of a market for the exchange bonds.

Certain persons who participate in the exchange offer must deliver a prospectus in connection with resales of the exchange bonds.

Based on interpretations of the staff of the SEC contained in Exxon Capital Holdings Corp., SEC no-action letter (available April 13, 1988), Morgan Stanley & Co. Inc., SEC no-action letter (available June 5, 1991) and Shearman & Sterling, SEC no-action letter (available July 2, 1983), we believe that you may offer for resale, resell or otherwise transfer the exchange bonds without compliance with the registration and prospectus delivery requirements of the Securities Act. However, in some instances described in this prospectus under "PLAN OF DISTRIBUTION," certain holders of exchange bonds will remain obligated to comply with the registration and prospectus delivery requirements of the Securities Act to transfer the exchange bonds. If a holder subject to the registration and prospectus delivery requirements of the Securities Act transfers any exchange bonds without delivering a prospectus meeting the requirements of the Securities Act or without an applicable exemption from registration under the Securities Act, that holder may incur liability under the Securities Act. We do not and will not assume or indemnify such a holder against this liability.

The following risk applies to the original bonds and will apply equally to the exchange bonds.

Any material differences between our actual results and the historical results contained in our annual, quarterly and current reports filed with the SEC could have a significant adverse impact on the market price of the exchange bonds, assuming a market for the exchange bonds develops. In addition, any downgrade of our credit ratings could have a significant adverse impact on the market price of the exchange bonds, assuming a market develops.

Some important factors, in addition to others specifically addressed in "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS," that could have a material negative impact on our operations, financial results and financial condition, or

could cause our actual results or outcomes to differ materially from any projected outcome contained in any forward-looking statement in this prospectus, include:

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

As with most electric utilities, we are subject to extensive federal, state and local laws and regulations regarding air and water quality which, among other things, regulate emissions of pollutants, such as particulate matter, sulfur dioxide, nitrogen oxides and mercury into the air and discharges of other pollutants, including heat, into waters. We are 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 us 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. To date, we have committed significant capital expenditures to achieve and maintain compliance with these regulatory requirements at our facilities, and we expect that we will make significant capital expenditures related to environmental compliance in the future.

While we will continue to exercise our best efforts to comply with all applicable regulations, there can be no assurance that we will always be in compliance with all current and future environmental requirements. Failure to comply with these requirements, even if this failure is caused by factors beyond our control, could result in the imposition of civil and criminal penalties against us, 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 our financial condition, the ultimate outcome of any of these actions cannot be predicted.

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

We may become subject to legislative and regulatory responses to climate change, with which compliance could be difficult and costly.

Efforts to limit emissions of carbon dioxide from power plants continue to increase. For example, the Waxman-Markey bill, which proposes to regulate carbon dioxide emissions, was introduced in Congress earlier this year and is currently being debated. The Environmental Protection Agency, or EPA, has issued an Advance Notice of Proposed Rulemaking that suggests various alternatives for regulating greenhouse gases under the Clean Air Act. The EPA has also made an "endangerment finding" for carbon dioxide, which, if carried through, would trigger a series of events that could result in the regulation of carbon dioxide as an air pollutant. Many of our electric generating facilities are likely to be subject to regulation under climate change laws and/or regulations which result from these activities within the next few years. In 2008, 51% of our generation, excluding pumped storage, came from our interest in the coal-fired Plants Scherer and Wansley, which would be the most impacted by

any greenhouse gas related legislation or regulation, while another 7% came from our gas-fired facilities (which would also be somewhat impacted but not to the same extent as the coal-fired facilities). The remaining generation (42%) came from our interest in the nuclear Plants Vogtle and Hatch and would not likely be impacted by any climate change legislation or regulation.

Many of the climate change legislative proposals use a "cap-and-trade" policy structure, in which carbon dioxide and other greenhouse gas emissions from some portion of the economy would be subject to an overall cap, which would decrease (i.e., become more stringent) over time. The proposals establish mechanisms for emissions sources, such as power plants, to obtain "allowances" or permits to emit carbon dioxide and other greenhouse gases during to the course of the year. This program would be similar to the emission allowance trading program for sulfur dioxide established by the Clean Air Act Amendments of 1990. However, unlike the program for sulfur dioxide, we and other utilities may need to purchase all or many of the necessary allowances in an auction format, rather than being issued allowances for no additional charge. Depending upon the price of available allowances, given the level of current emissions (our emissions of carbon dioxide in 2008 totaled about 13 million tons) and the limited, short-term options available to reduce emissions in the existing generation fleet, the cost to purchase needed allowances may be substantial if this legislation is enacted as proposed.

We own nuclear facilities, which give rise to environmental, regulatory, financial and other risks, and we are participating in the development of new nuclear facilities.

We own 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 our generating capacity. Our ownership interest in these facilities exposes us to various risks, including:

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. We currently forecast that the on-site storage capabilities at Plants Hatch and Vogtle can be expanded to accommodate spent fuel through the life of the plants.

We maintain an internal fund and an external trust fund for the expected cost of decommissioning our nuclear facilities; however, it is possible that decommissioning costs and liabilities could exceed the amount of these funds. Additionally, our 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 we have no reason to

anticipate a serious incident at either of these plants, if an incident did occur, it could result in substantial costs to us. A major incident at a nuclear facility anywhere in the world could cause the Nuclear Regulatory Commission to limit or prohibit the operation or licensing of any domestic nuclear unit.

In addition to our existing ownership of nuclear units, we are participating with the other co-owners of Plant Vogtle in the construction of two additional nuclear units at the Plant Vogtle site. See "OUR BUSINESS—Future Power Resources—Plant Vogtle Units No. 3 and No. 4."

We are exposed to uncertainty of capital expenditures in connection with construction projects at our existing generating facilities and for the construction of new generating facilities.

Our existing facilities require ongoing capital expenditures in order to maintain efficient and reliable operations. Many of our facilities were constructed over 20 to 30 years ago and, as a result, may require significant capital expenditures in order to maintain efficiency and reliability, and to comply with changing environmental requirements.

In addition, due to projected growth in their service territories, our members may request that we expand our existing generating facilities or build or acquire new generating facilities, which would require significant capital expenditures. Our members have subscribed to our participation in ownership of 30% of two additional nuclear units at Plant Vogtle and construction of two 100 megawatt biomass-fueled power plants. Our members have also given general approval for the future development of certain quantities of gas-fired combustion turbine plants and combined cycle plants, subject to future member subscription for specific projects only as needed.

The completion of construction projects without delays or cost overruns is subject to substantial risks, including:

In addition, the construction of large generating plants involves significant financial risk. Moreover, no nuclear plants have been constructed in the United States using advanced designs. Therefore, estimating the cost of construction of any new nuclear plant is inherently uncertain and, as a result, we could be exposed to additional risk of cost uncertainty in connection with these projects.

All of these risks could have the effect of increasing the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

Our ability to access capital could be adversely affected by various factors, including current market conditions and potential limitations on the availability of Rural Utilities Service loans, and significant constraints on our access to capital could adversely affect our financial condition and results of operations.

We rely on access to external funding sources as a significant source of liquidity for capital requirements not satisfied by cash flow generated from operations. Historically, we and other electric

generating cooperatives have relied on federal loan programs guaranteed by the Rural Utilities Service in order to meet a significant portion of our long-term financing needs, typically at a cost that was lower than traditional capital markets financing. However, the availability and magnitude of annual Rural Utilities Service funding levels are subject to the federal budget appropriations process, and therefore are subject to uncertainty because of periodic budgetary and political pressures faced by Congress. In addition, a new wave of generation construction nationwide among electric cooperatives is resulting in increased competition for available Rural Utilities Service funding levels. Further, there is currently a moratorium in place at the Rural Utilities Service regarding the funding of new baseload (coal and nuclear) generating facilities. If the amount of Rural Utilities Service-guaranteed loan funds available to us in the future is further decreased or eliminated, we may have to seek alternative sources of financing which will likely be at a higher cost.

Therefore, our reliance on access to both short-term and long-term capital market funding has become an increasingly important factor, particularly in light of the significant amount of new generation construction that we have planned over the next decade to meet the future energy needs of our members. We have successfully accessed the capital markets in the past, and believe that we will maintain sufficient access to capital markets based on our current credit ratings. However, our credit ratings reflect the views of the rating agencies, which could change at any point in the future. Our borrowing costs could increase and our potential pool of investors, funding sources and liquidity could decrease if our credit ratings were lowered, particularly if our ratings were lowered below investment grade.

In addition, certain market disruptions could constrain, at least temporarily, our ability to maintain sufficient liquidity and to access capital on favorable terms or at all. These disruptions include:

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

We could be adversely affected if we are unable to continue to operate our facilities in a successful manner.

The operation of our generating facilities may be adversely impacted by various factors, including:

These or similar negative events could interrupt or limit electric generation or increase the cost of operating our facilities, which could have the effect of increasing the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

Changes in fuel prices could have an adverse effect on our cost of electric service.

We are exposed to the risk of changing prices for fuels, including coal, natural gas and uranium. We have taken steps to manage this exposure by entering into fixed or capped price contracts for some of our coal requirements. We have also entered into natural gas swap arrangements on behalf of some of our members designed to manage the exposure of those members to fluctuations in the price of natural gas. The operator of our nuclear plants manages price and supply risk through use of long-term fixed or capped price contracts with multiple vendors of uranium ore mining, conversion and enrichment services. However, these arrangements do not cover all of our and our members' risk exposure to increases in the prices of fuels. Therefore, increases in fuel prices could significantly increase the cost of electric service we provide to our members and affect their ability to perform their contractual obligations to us.

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

We obtain our fuel supplies, including coal, natural gas and uranium, from a number of different suppliers. Any disruptions in our fuel supplies, including disruptions due to weather, labor relations, environmental regulations, or other factors affecting our fuel suppliers, could result in us 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 our 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. Any failure to maintain an adequate inventory of fuel supplies could require us to operate other generating plants at higher cost or require our members to purchase higher-cost energy from other sources, and affect their ability to perform their contractual obligations to us.

The financial difficulties faced by other companies could adversely affect us.

We have exposure to many different industries and counterparties, and routinely execute transactions with counterparties in the energy industry, such as coal and natural gas companies, and the financial services industry, including commercial banks, investment banks and other institutions. Many of these transactions expose us to credit risk in the event of default of our counterparty. For example, we enter into hedge agreements to manage a portion of our exposure to fluctuations in the market price of natural gas with several counterparties. If our counterparties fail or refuse to honor their obligations, our hedges of the related risk may be ineffective. Any failure could significantly increase the cost of electric service we provide to our members.

Also, as a result of recent market events, some of our financial institution counterparties have experienced various degrees of financial distress, including liquidity constraints and credit downgrades. The financial distress of these counterparties may have an adverse effect on us in the event that these counterparties default or otherwise fail to meet their obligations to us. For example, the recent credit downgrades of AMBAC Indemnity Corporation and American International Group, Inc. have triggered

certain requirements under certain of our agreements. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Off-Balance Sheet Arrangements-Rocky Mountain Lease Arrangements," "—Negative Events In the Capital Markets," and "—Financing Activities."

Our ability to meet our financial obligations could be adversely affected if our members fail to perform their contractual obligations to us.

We depend primarily on revenue from our members under the wholesale power contracts to meet our financial obligations. Our members are our owners and we do not control their operations or financial performance. Further, our members must forecast their load growth and power supply needs. If our members acquire more power supply resources than needed, whether from us or other suppliers, or fail to acquire sufficient supplies, our members' rates could increase excessively and affect financial performance. As a result of current economic conditions, sales by our members may not be sufficient to cover current costs without rate increases. Our members may not collect all amounts billed to their consumers. Although each member has financial covenants to set rates to maintain certain margin levels, and our members' rates are not regulated by the Georgia Public Service Commission, pressure from their consumer members not to raise rates excessively could affect financial performance. Thus, we are exposed to the risk that one or more members could default in the performance of their obligations to us under the wholesale power contracts. Our ability to satisfy our financial obligations could be adversely affected if one or more of our members, particularly one of the larger members, defaulted on their payment obligations to us. Although the wholesale power contracts obligate non-defaulting members to pay the amount of any payment default, pursuant to a pro rata step-up formula, there can be no guarantee that the non-defaulting members would be able to fulfill this obligation.

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

Our business model is to provide our members with wholesale electric power at the lowest possible cost. Other technologies currently exist or are in development, such as fuel cells, microturbines, windmills and solar cells, that may in the future be capable of producing electric power at costs that are comparable with, or lower than, our cost of generating power. If these technologies were to develop sufficient economies of scale, the value of our generating facilities could be adversely affected.

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

Under current Georgia law, our 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 legislation concerning retail competition 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 we and our members are unable to adapt to any of these changes, the prices we charge for electric service could become less competitive. While we provide electric service to our members under long-term, take-or-pay contracts providing for joint and several liability among our members, if one or more of our members were to experience significant financial losses as a result of increased competition, our members may have difficulty performing their obligations to us under their wholesale power contracts.

This prospectus contains "forward-looking statements." All statements, other than statements of historical facts, that are included in this prospectus, that address activities, events or developments that we expect or anticipate to occur in the future, including matters such as future capital expenditures, business strategy and development or operation of facilities (often, but not always, through the use of words or phrases such as "will likely result," "are expected to," "will continue," "is anticipated," "estimated," "projection," "target" and "outlook"), are forward-looking statements. Although we believe that in making these forward-looking statements our expectations are based on reasonable assumptions, any forward-looking statement involves uncertainties and is qualified in its entirety by reference to the discussion of risk factors discussed under "RISK FACTORS" and the following important factors, among others, that could cause our actual results to differ materially from those projected in any forward-looking statement:

Any forward-looking statement speaks only as of the date on which it is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances after the date on which it is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time, and it is not possible for us to predict all of them; nor can we assess the impact of each factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.

We will not receive any cash proceeds from the issuance of the exchange bonds pursuant to the exchange offer. In consideration for issuing the exchange bonds as contemplated in this prospectus, we will receive in exchange a like principal amount of original bonds. The original bonds surrendered in exchange for the exchange bonds will be retired and cancelled and cannot be reissued. Accordingly, the issuance of the exchange bonds will not result in any change in our capitalization.

The summary financial data below present selected historical information relating to our financial condition and results of operations as of and for each of the years ended December 31, 2008, 2007, 2006, 2005 and 2004, as of and for the three-months ended March 31, 2009 and results of operations for the three-months ended March 31, 2008. Summary financial data for the years ended December 31, 2008, 2007, 2006, 2005 and 2004 that are presented below were derived from our audited consolidated financial statements. Summary financial data for the three months ended March 31, 2009 and 2008 that are presented below were derived from our unaudited financial statements. The unaudited financial statements include all adjustments, consisting of normal recurring adjustments, which we consider necessary for a fair presentation of our financial condition and results of operations for these periods. You should read the information contained in this table together with our financial statements, the related notes to the financial statements and the discussion of this information in this prospectus.

We are a Georgia electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by our 38 retail electric distribution cooperative members. Our principal business is providing wholesale electric power to our members. As with cooperatives generally, we operate on a not-for-profit basis. We are the largest electric cooperative in the United States in terms of assets, kilowatt-hour sales to members and, through our members, consumers served. We are also the second largest power supplier in the state of Georgia.

Our members are local consumer-owned distribution cooperatives providing retail electric service on a not-for-profit basis. In general, our members' customer base consists of residential, commercial and industrial consumers within specific geographic areas. Our members serve approximately 1.7 million electric consumers (meters) representing approximately 4.1 million people. (See "Our Members and Their Power Supply Resources.")

We provide wholesale electric service to our members for a substantial portion of their requirements from a combination of our generation assets and purchased power. We provide this service pursuant to the wholesale power contracts. The wholesale power contracts obligate our members on a joint and several basis to pay rates sufficient to recover all the costs of owning and operating our power supply business, to provide for the establishment and maintenance of reasonable reserves, and to enable us to comply with all financial requirements under the indenture.

For selected information on our members, including consumers served, megawatt-hour sales, annual revenues, operating results, and balance sheet information, see "MEMBERS' FINANCIAL AND STATISTICAL INFORMATION" in APPENDIX A.

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

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

We provide wholesale electric service to our members for a substantial portion of their power requirements from a combination of our generation assets and power purchased from power marketers and other suppliers. We provide 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 obligate our members jointly and severally to pay rates sufficient to recover all the costs of owning and operating our power supply business, including the payment of principal and

interest on our indebtedness. Our members satisfy all of their power requirements above their purchase obligations to us with purchases from other suppliers. (See "Our Members and Their Power Supply Resources—Member Power Supply Resources.")

We have interests in 27 generating units. These units provide us with a total of 5,244 megawatts of nameplate capacity, consisting of 1,501 megawatts of coal-fired capacity, 1,185 megawatts of nuclear-fueled capacity, 632 megawatts of pumped storage hydroelectric capacity, 1,911 megawatts of gas-fired capacity (206 megawatts of which is capable of running on oil) and 15 megawatts of oil-fired combustion turbine capacity. We also purchase approximately 300 megawatts of power pursuant to a long-term power purchase agreement. (See "Our Power Supply Resources" and "Properties—Generating Facilities.")

In 2008, three of our members, Cobb Electric Membership Corporation, Jackson Electric Membership Corporation and Sawnee Electric Membership Corporation, accounted for 12.8%, 11.4% and 10.4% of our total revenues, respectively. None of our other members accounted for as much as 10% of our total revenues in 2008.

We have substantially similar wholesale power contracts with each member extending through December 31, 2050. Under the wholesale power contracts, each member is unconditionally obligated, on an express "take-or-pay" basis, for a fixed percentage of the capacity costs of each of our 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. We are obligated to use our reasonable best efforts to operate, maintain and manage our resources in accordance with prudent utility practices.

We have assigned fixed percentage capacity costs responsibilities to our members for all of our generation and purchased power resources. For any future resource, we will assign fixed percentage capacity costs responsibilities only to members choosing to participate in that resource. The wholesale power contracts provide that each member is jointly and severally responsible for all costs and expenses of all existing generation and purchased power resources, as well as for any approved future resources, whether or not that member has elected to participate in the future resource. For resources so approved in which less than all members participate, costs are shared first among the participating members, and if all participating members default, each non-participating member is expressly obligated to pay a proportionate share of the default.

To acquire future resources, we are required to obtain the approval of 75% of the members of our board of directors, 75% of our members and members representing 75% of our patronage capital. We can make certain resource modifications if approved by more than 50% of the members of our board of directors and 50% of our members.

Under the wholesale power contracts, we are not obligated to provide all of our members' capacity and energy requirements. Individual members must satisfy all of their requirements above their purchase obligations from us from other suppliers, unless we and our members agree that we will supply additional capacity and associated energy, subject to the approval requirements described above. In 2008, we supplied energy that accounted for approximately 65% of our members' retail energy requirements. (See "Our Members and Their Power Supply Resources—Member Power Supply Resources.")

Under the wholesale power contracts, each member must establish rates and conduct its business in a manner that will enable the member to pay (i) to us when due, all amounts payable by the member under its wholesale power contract and (ii) any and all other amounts payable from, or which might constitute a charge or a lien upon, the revenues and receipts derived from the member's electric

system, including all operation and maintenance expenses and the principal of, premium, if any, and interest on all indebtedness related to the member's electric system.

In 2003, we entered into a New Business Model Member Agreement with our members that requires member approval for us to undertake certain activities. The agreement does not limit our ability to own, manage, control and operate our resources or perform our functions under the wholesale power contracts.

We may not provide services unrelated to our resources or our functions under the wholesale power contracts if these services would require us to incur indebtedness, provide a guarantee or make any loan or investment, unless approved by 75% of the members of our board of directors, 75% of our members, and members representing 75% of our patronage capital. We may provide any other unrelated service to a member so long as (i) doing so would not create a conflict of interest with respect to other members, (ii) the service is being provided to all members or (iii) the service has received the three 75% approvals described above.

Each member is required to pay us for capacity and energy furnished under its wholesale power contract in accordance with rates we establish. We review our rates at intervals that we deem appropriate but are required to do so at least once every year. We are required to revise our rates as necessary so that the revenues derived from our rates, together with our revenues from all other sources, will be sufficient to pay all of the costs of our system, including the payment of principal and interest on our indebtedness, to provide for reasonable reserves and to meet all financial requirements.

Our principal financial requirements are contained in the Indenture, dated as of March 1, 1997, from us to U.S. Bank National Association, as trustee (successor to SunTrust Bank), as amended and supplemented. Under the indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates which are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. Margins for interest ratio is the ratio of margins for interest to total interest charges for a given period. Margins for interest is the sum of:

Margins for interest takes into account any item of net margin, loss, gain or expenditure of any of our affiliates or subsidiaries only if we have received the net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if we have made a payment with respect to the losses or expenditures.

The formulary rate we established in the rate schedule to the wholesale power contracts employs a rate methodology under which all categories of costs are specifically separated as components of the

formula to determine our revenue requirements. The rate schedule also implements the responsibility for fixed costs assigned to each member based on each members' fixed percentage capacity costs responsibilities for all of our generation and purchased power resources. The monthly charges for capacity and other non-energy charges are based on our annual budget. These capacity and other non-energy charges may be adjusted by our board of directors, if necessary, during the year through an adjustment to the annual budget. Energy charges reflect the pass-through of actual energy costs, including fuel costs, variable operations and maintenance costs and purchased energy costs. (See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Summary of Cooperative Operations—Rates and Regulation.")

The rate schedule formula also includes a prior period adjustment mechanism designed to ensure that we achieve the minimum 1.10 margins for interest ratio. Amounts, if any, by which we fail to achieve a minimum 1.10 margins for interest ratio are accrued as of December 31 of the applicable year and collected from our members during the period April through December of the following year. The rate schedule formula is intended to provide for the collection of revenues which, together with revenues from all other sources, are equal to all costs and expenses we recorded, plus amounts necessary to achieve at least the minimum 1.10 margins for interest ratio. To enhance the financial coverage during an anticipated period of generation facility construction, our board of directors approved a budget for 2009 to achieve a 1.12 margins for interest ratio. Our board of directors will evaluate coverage ratios throughout the period of anticipated construction and may choose to increase or decrease margins for interest coverage in the future.

Under the indenture and related loan contract with the Rural Utilities Service, adjustments to our rates to reflect changes in our budgets are generally not subject to Rural Utilities Service approval. Changes to the rate schedule under the wholesale power contracts are generally subject to Rural Utilities Service approval. Our rates are not subject to the approval of any other federal or state agency or authority, including the Georgia Public Service Commission.

Smarr EMC is a Georgia electric membership corporation owned by 36 of our 38 members. Smarr EMC owns two combustion turbine facilities with aggregate capacity of 709 megawatts. We provide operations, financial and management services for Smarr EMC. (See "The Members and Their Power Supply Resources—Member Power Supply Resources.")

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

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

Georgia Transmission has rights in the integrated transmission system, which consists of transmission facilities owned by Georgia Transmission, Georgia Power Company, the Municipal Electric Authority of Georgia and the City of Dalton, Georgia. Through agreements, common access to the

combined facilities that compose the integrated transmission system enables the owners to use their combined resources to make deliveries to or for their respective consumers, to provide transmission service to third parties and to make off-system purchases and sales. The integrated transmission system was established in order to obtain the benefits of a coordinated development of the parties' transmission facilities and to make it unnecessary for any party to construct duplicative facilities.

We, Georgia Transmission and our 38 members are members of Georgia System Operations Corporation, which was formed in 1997 to own and operate the system operations business we previously owned. Georgia System Operations operates the system control center and currently provides Georgia Transmission and us with system operations services and administrative support services. We have contracted with Georgia System Operations to schedule and dispatch our resources. We have also purchased from Georgia System Operations services that it purchases from Georgia Power under the control area compact, which we co-signed with Georgia System Operations. (See "The Members and Their Power Supply Resources—Members' Relationship with Georgia Transmission and Georgia System Operations.") Georgia System Operations provides support services to us in the areas of accounting, auditing, communications, human resources, facility management, telecommunications and information technology at cost-based rates.

We have a modest amount of loans, as of March 31, 2009, approximately $9 million outstanding to Georgia System Operations, primarily for the purpose of financing capital expenditures. Georgia System Operations has an additional $3 million that can be drawn under one of its loans with us.

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

Historically, federal loan programs administered by the Rural Utilities Service, an agency of the United States Department of Agriculture, have provided the principal source of financing for electric cooperatives. Loans guaranteed by the Rural Utilities Service and made by the Federal Financing Bank have been a major source of funding for us. However, the availability and magnitude of Rural Utilities Service-guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, Rural Utilities Service-guaranteed loan funds are subject to increased uncertainty because of budgetary and political pressures faced by Congress. The Rural Utilities Service has indicated that the administration's position is that the Rural Utilities Service will no longer provide loan guarantees for new baseload (coal and nuclear) generation. Although in its 2009 budget proposal, the prior administration requested a decrease in funding for the guaranteed loan program, Congress adopted a 2009 budget that continued funding at the level of prior years. The President's budget for fiscal year 2010 proposes to continue funding at these same levels. Because of these factors, we cannot predict the amount or cost of Rural Utilities Service-guaranteed loans that may be available to us in the future.

We have a loan contract with the Rural Utilities Service in connection with the indenture. Under the loan contract, the Rural Utilities Service has approval rights over certain significant actions and arrangements, including, without limitation,

The extent of the Rural Utilities Service's approval rights under the loan contract with us is substantially less than the supervision and control Rural Utilities Service has traditionally exercised over borrowers under its standard loan and security documentation. In addition, the indenture improves our ability to borrow funds in the capital markets relative to the Rural Utilities Service's standard mortgage. The indenture constitutes a lien on substantially all of the tangible and certain intangible property we own.

Our relationship with Georgia Power is a significant factor in several aspects of our business. Georgia Power is responsible for the operation of all of our co-owned generating facilities, except the Rocky Mountain Pumped Storage Hydroelectric Facility, on behalf of itself as a co-owner and as agent for the other co-owners. Georgia Power supplies services to us and Georgia System Operations to support the scheduling and dispatch of our resources, including off-system transactions. Georgia Power and our members are competitors in the State of Georgia for electric service to any new customer that has a choice of supplier under the Georgia Territorial Electric Service Act, which was enacted in 1973, commonly known as the Georgia Territorial Act. For further information regarding the agreements with Georgia Power and us and our members' relationships with Georgia Power, see "Our Members and Their Power Supply Resources—Service Area and Competition" and "Properties—Fuel Supply," "Properties—Co-Owners of Plants—Georgia Power Company" and "—The Plant Agreements."

Under current Georgia law, our members generally have the exclusive right to provide retail electric service in their respective territories. Since 1973, however, the Georgia Territorial Act has permitted limited competition among electric utilities located in Georgia for sales of electricity to certain large commercial or industrial customers. The owner of any new facility may receive electric service from the power supplier of its choice if the facility is located outside of municipal limits and has a connected load upon initial full operation of 900 kilowatts or more. Our members are actively engaged in competition with other retail electric suppliers for these new commercial and industrial loads. While the competition for 900-kilowatt loads represents only limited competition in Georgia, this competition has given our 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 Georgia Territorial Act or otherwise affect the exclusive right of our members to supply power to their current service territories. The Georgia Public Service Commission does not have the authority under Georgia law to order retail competition or amend the Georgia Territorial Act.

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

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

We continue to consider, along with our members, a wide array of other potential actions to meet future power supply needs, to reduce costs, to reduce risks of the competitive generation business and to respond to competition. Alternatives that could be considered include:

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

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

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

Further, a member's power supply planning may include consideration of assignment of its rights and obligations under its wholesale power contract to another member or a third party. We have existing provisions for wholesale power contract assignment, as well as provisions for a member to withdraw and concurrently to assign its rights and obligations under its wholesale power contract. Assignments upon withdrawal require the assignee to have certain published credit ratings and to assume all of the withdrawing member's obligations under its wholesale power contract with us, and

must be approved by our board of directors. Assignments without withdrawal are governed by the wholesale power contract and must be approved by both our board of directors and the Rural Utilities Service.

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

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

Our members' demand for energy is influenced by seasonal weather conditions. Historically, our 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 our fixed costs, which do not vary significantly from month to month; therefore, capacity charges are billed and capacity revenues are recognized in substantially equal monthly amounts.

We supply capacity and energy to our members for a portion of their requirements from a combination of our generating assets and power purchased from other suppliers. In 2008, we supplied approximately 65% of our members' retail energy requirements.

Our 27 generating units consist of 30% undivided interests in the Edwin I. Hatch Plant, the Alvin W. Vogtle Plant and the Hal B. Wansley Plant, a 60% undivided interest in the Robert W. Scherer Unit No. 1, and the Robert W. Scherer Unit No. 2, a 74.61% undivided interest in Rocky Mountain, a 100% interest in the Talbot Energy Facility, a 100% interest in the Chattahoochee Energy Facility and a 100% interest in the Doyle I, LLC Generating Plant through a power purchase agreement that we treat as a capital lease, a 100% interest in the Heard County Energy Facility, through our wholly owned subsidiary, Heard County Power, L.L.C., all totaling 5,244 megawatts of nameplate capacity.

The Municipal Electric Authority of Georgia, the City of Dalton and Georgia Power also have interests in Plants Hatch, Vogtle and Wansley and Scherer Units No. 1 and No. 2. Georgia Power serves as operating agent for these units. Georgia Power also has an interest in Rocky Mountain, which we operate.

See "Business Overview" for a description of our generating facilities, fuel supply and the co-ownership arrangements.

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

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

In addition, we also purchase small amounts of capacity and energy from "qualifying facilities" under the Public Utility Regulatory Policies Act of 1978. Under a waiver order from the Federal Energy Regulatory Commission, we historically made all purchases the members would have otherwise been required to make under Public Utility Regulatory Policies Act and we were relieved of our obligation to sell certain services to "qualifying facilities" so long as the members make those sales. Our purchases from such qualifying facilities provided less than 0.1 percent of our energy requirements for the members in 2008. Under their wholesale power contracts, the members may now make such purchases instead of us.

In conjunction with our acquisition of Heard County Power, L.L.C., we accepted assignment of a power purchase and sale agreement pursuant to which we sell 500 megawatts of capacity and associated energy to seven of our members, with a term through December 31, 2015.

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

We are participating in 30% of the costs of the construction of two additional nuclear units at Plant Vogtle, Units No. 3 and No. 4, scheduled for commercial operation in 2016 and 2017.

Georgia Power, for itself and as agent for Oglethorpe, The Municipal Electric Authority of Georgia and the City of Dalton (the Owners), has signed an Engineering, Procurement and Construction Contract with Westinghouse Electric Company, LLC and Stone & Webster, Inc. (the Consortium). Pursuant to the contract, the Consortium will supply and construct two 1,100 megawatt nuclear units using the Westinghouse AP1000 technology, with the exception of certain owner supplied items. Under the contract, the Owners will pay a purchase price that is subject to certain price escalation and adjustments, adjustments for change orders and performance bonuses. Each Owner is severally, not jointly, liable to the Consortium based on its ownership share. The contract includes certain liquidated damages upon the Consortium's failure to comply with schedule and performance

guarantees, as well as certain bonuses payable to the Consortium for early completion and unit performance. The Consortium's liability for those liquidated damages and for warranty claims is subject to a cap. The obligations of Westinghouse and Stone & Webster are guaranteed by their parent companies Toshiba Corporation and The Shaw Group, Inc., respectively. In the event of certain credit rating downgrades of any Owner, that Owner would be required to provide a letter of credit or other credit enhancement to the Consortium. In addition, the Owners may terminate the contract at any time for their convenience, provided that the Owners will be required to pay certain termination costs and, at certain stages of the work, cancellation fees to the Consortium. The Consortium may terminate the contract under certain circumstances, including delays in receipt of the combined construction permits and operating licenses or delivery of full notice to proceed, certain Owner suspension or delays of work, action by a governmental authority to permanently stop work, certain breaches of the contract by the Owners, Owner insolvency and certain other events.

Our rights and obligations with respect to these additional units are contained in an Ownership Participation Agreement, the Plant Vogtle Operating Agreement (amended to include Units No. 3 and No. 4), and the Nuclear Managing Board Agreement (amended to include Units No. 3 and No. 4). The Ownership Participation Agreement is similar to the agreement that covers Units No. 1 and No. 2.

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

Five entities intervened in the Plant Vogtle early site permit process. The Nuclear Regulatory Commission appointed an Atomic Safety and Licensing Board panel to rule on the contentions of the intervenors. An Atomic Safety and Licensing Board panel hearing was held in March 2009, after which the panel will provide a final ruling on the contentions.

An Atomic Safety and Licensing Board panel was also appointed to preside over hearings in the combined construction permit and operating license proceeding. The Nuclear Regulatory Commission schedule for this proceeding contemplates a decision in 2011.

Our estimated total costs for the new units, including allowance for funds used during construction, are approximately $4.2 billion. We have submitted a loan application to the Department of Energy seeking partial funding for these proposed nuclear units. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" and "—Financing Activities."

We are pursuing development of two 100 megawatt biomass-fueled generating plants that have been subscribed by members. The plants are planned for commercial operation in 2014 and 2015. We are currently in the process of acquiring sites and conducting preliminary engineering work.

Our construction budget for these two projects is $933 million, including allowance for funds during construction. However, no significant capital expenditures will be required until after 2011. We have submitted a loan application to the Rural Utilities Service for financing of these projects. See "MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Capital Requirements—Capital Expenditures" and "—Financing Activities."

From time to time, we may assist our members in investigating potential new power supply resources, after compliance with the terms of the New Business Model Member Agreement (see "Business Overview—New Business Model Member Agreement"). Our members requested that we assist them with an evaluation of future power supply needs. In addition to Vogtle Units No. 3 and No. 4 and the biomass plants, we have identified for our members other future generation resource development possibilities to help meet their power supply needs over the next ten years. Our members have given general approval for the future development of certain quantities of gas-fired combustion turbine plants and combined cycle plants, subject to future member subscription for specific projects only as needed. We are continuing development activities to be prepared for construction as needed.

Our members, each an electric membership corporation, or EMC, are listed below and include 38 of the 42 electric distribution cooperatives in the State of Georgia.

Our members serve approximately 1.7 million electric consumers (meters) representing approximately 4.1 million people. Our 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 our members in 2008 amounted to approximately 34 million megawatt hours, with approximately 68% to residential consumers, 29% to commercial and industrial consumers and 3% to other consumers. Our members are the principal suppliers for the power needs of rural Georgia. While our members do not serve any major cities, portions of their service territories are in close proximity to urban areas and have experienced substantial growth over the years due to the expansion of urban areas, including metropolitan Atlanta. Our 38 members have experienced approximate average annual compound growth rates from 2006 through 2008 of 2.2% in number of consumers, 2.1% in megawatt-hour sales and 5.5% in electric revenues.

The following table shows the aggregate peak demand and energy requirements of our 38 members for the years 2006 through 2008, and also shows the amounts of energy requirements we

supplied. From 2006 through 2008, demand and energy requirements of the members increased at an average annual compound growth rate of 2.9% and 1.2%, respectively.

The Georgia Territorial Act regulates the service rights of all retail electric suppliers in the State of Georgia. Pursuant to the Georgia Territorial Act, the Georgia Public Service Commission assigned substantially all areas in the State to specified retail suppliers. With limited exceptions, our 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 Georgia 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 Georgia Public Service Commission may reassign territory only if it determines that an electric supplier has breached the tenets of public convenience and necessity. The Georgia Public Service Commission may transfer service for specific premises only if: (i) the commission 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 commission 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 the premise and the electric utility is unwilling or unable to comply with an order from the commission regarding the service.

Since 1973, the Georgia 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. Our members, with our 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 our members continues to increase annually. While the competition for 900-kilowatt loads represents only limited competition in Georgia, this competition has given our members and us the opportunity to develop resources and strategies to operate in an increasingly competitive market.

For further information regarding member competitive activities, see "Business Overview—Competition."

Our 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 our 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 the Rural Utilities Service or loan documents with other lenders. The Rural Utilities Service mortgages generally prohibit these distributions unless (i) after any of these distributions, the member's total equity will equal at least 30% of its total assets or (ii) 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% (see "Members' Relationship with the Rural Utilities Service").

We are a membership corporation, and our members are not our subsidiaries. Except with respect to the obligations of our members under each member's wholesale power contract with us and our rights under these contracts to receive payment for power and energy supplied, we have no legal interest in (including through a pledge or otherwise), or obligations in respect of, any of the assets, liabilities, equity, revenues or margins of our members. (See "Business Overview—Wholesale Power Contracts.") The assets and revenues of our members are, however, pledged under their respective mortgages with the Rural Utilities Service or loan documents with other lenders.

We depend on the revenue we receive from our members pursuant to the wholesale power contracts to cover the costs of the operation of our power supply business and satisfy our debt service obligations.

Through provisions in the loan documents securing loans to the members, Rural Utilities Service exercises control and supervision over the rates for the sale of power of our members that borrow from it. The Rural Utilities Service mortgage indentures of these 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 Rural Utilities Service, but the Georgia Territorial Act prohibits the members from unreasonable discrimination in the setting of rates, charges, service rules or regulations and requires the members to obtain Georgia Public Service Commission approval of long-term borrowings.

Cobb Electric Membership Corporation, Diverse Power Incorporated, an Electric Membership Corporation, Mitchell Electric Membership Corporation, Oconee Electric Membership Corporation, Snapping Shoals Electric Membership Corporation and Walton Electric Membership Corporation have repaid all of their Rural Utilities Service indebtedness and are no longer Rural Utilities Service 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 Rural Utilities Service borrower engages in wholesale sales or sales of transmission service in interstate commerce, it would, in certain circumstances, be subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act.

Through provisions in the loan documents securing loans to the members, the Rural Utilities Service 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 the Rural Utilities Service to electric cooperatives have been a major source of funding for the members. Under the current Rural Utilities Service loan programs, electric distribution borrowers are eligible for loans made by the Federal Financing Bank or other lenders and guaranteed by the Rural Utilities Service. Certain borrowers with either low consumer density or higher than average rates and lower than average consumer income are eligible for special loans that bear interest at an annual rate of 5%. However, the availability and magnitude of Rural Utilities Service direct and guaranteed loan funds is subject to annual federal budget appropriations and thus cannot be assured. Currently, the availability of Rural Utilities Service loan funds is subject to increased uncertainty because of budgetary pressures faced by Congress.

Although in its 2009 budget proposal, the prior administration requested a decrease in funding for the guaranteed loan program, which provides funding for electric generation and transmission borrowers, as well as electric distribution borrowers, Congress adopted a 2009 budget that continued funding at the level of prior years. The President's budget for fiscal year 2010 proposes to continue funding at these same levels. We cannot predict the amount or cost of Rural Utilities Service direct and guaranteed loans that may be available to the members in the future.

Georgia Transmission provides transmission services to our members for delivery of our members' power purchases from us and other power suppliers. Georgia Transmission and the members have entered into member transmission service agreements under which Georgia Transmission provides transmission service to the members pursuant to a transmission tariff. The member transmission service agreements have a minimum term for network service until December 31, 2040; however, Georgia Transmission has signed an amendment with each of its members to extend the agreements through December 31, 2060. These amendments are awaiting Rural Utilities Service approval. The members transmission service agreements include certain elections for load growth above 1995 requirements, with notice to Georgia Transmission, to be served by others. These agreements also provide that if a member elects to purchase a part of its network service elsewhere, it must pay appropriate stranded costs to protect the other members from any rate increase that they could otherwise occur. Under the member transmission service agreements, members have the right to design, construct and own new distribution substations.

Georgia System Operations has contracts with each of its members, including Georgia Transmission and us, to provide to them the services that it purchases from Georgia Power under the Control Area Compact, which we co-signed with Georgia System Operations. Georgia System Operations also provides operation services for the benefit of our members through agreements with us, including dispatch of our resources and other power supply resources owned by the members.

For additional information about our members' relationship with Georgia System Operations, see "Business Overview—Relationship with Georgia System Operations."

In 2008, we supplied approximately 65% of our members' retail energy requirements. Each member has a take-or-pay, fixed percentage capacity costs responsibility for all of our existing

resources. (See "Business Overview—Wholesale Power Contracts.") Additionally, in April 2009, we assumed a power purchase and sale agreement with seven of our members in connection with our acquisition of Heard County Power, L.L.C. (See "Our Power Supply Resources—Power Purchase and Sale Agreements—Power Sales.") Our members satisfied all of their requirements above their purchase obligations to us with purchases from other suppliers as described below.

Our members purchase hydroelectric power from the Southeastern Power Administration (SEPA) under contracts that extend until 2016. In 2008, the aggregate SEPA allocation to the members was 562 megawatts plus associated energy. Each member must schedule its energy allocation, and each member has designated us to perform this function. Pursuant to a separate agreement, we schedule, through Georgia System Operations, our 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.

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 megawatt gas-fired combustion turbine facility (with 35 participating members), and Sewell Creek Energy Facility, a four-unit, 492 megawatt 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. See "Business Overview—Relationship with Smarr EMC."

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

Our members are obtaining their remaining 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 2 to 9 years, some contracts, for fixed quantities, extend more than 20 years. The other members use a portfolio of power purchase contracts to meet their requirements.

We have not undertaken to obtain a complete list of member power supply resources. Any of our members may have committed or may commit to additional power supply obligations not described above.

For information about members' activities relating to their power supply planning, see "Business Overview—Competition" and "Business Overview—Future Power Resources." In addition to future power supply resources that we may acquire for our members, the members will likely also continue to acquire future resources from other suppliers, including suppliers that may be owned by members.

As is typical for electric utilities, we are subject to various federal, state and local air and water quality requirements which, among other things, regulate emissions of pollutants, such as particulate matter, sulfur dioxide, nitrogen oxides and mercury into the air and discharges of other pollutants, including heat, into waters of the United States. We are 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. Although it is our intent to comply with current and future regulations, we cannot provide assurance that we will always be in compliance with current and future regulations.

Our capital expenditures and operating costs will continue to reflect compliance with environmental standards. For 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."

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 us is the Clean Air Act, which has required reductions in emissions of sulfur dioxide, nitrogen oxides and mercury from affected electric utility units, which include the coal-fired units at Plants Wansley and Scherer.

Sulfur dioxide reductions are being imposed through a sulfur dioxide emission allowance trading program established under the 1990 amendments to the Clean Air Act. Pursuant to regulations issued by the U.S. Environmental Protection Agency, or EPA, aggregate emissions of sulfur dioxide from all affected units are now capped at 8.9 million tons per year. Tradable emission allowances, which authorize the emission of one ton of sulfur dioxide during a particular calendar year or thereafter, are issued 30 years in advance and are transferable. We are currently complying with this program by using lower-sulfur fuel and emission allowances. Flue gas desulfurization equipment, commonly known as scrubbers, will be completed by mid-2009 at Plant Wansley and is in the design phase at Plant Scherer to comply with these regulations along with other regulations as discussed below.

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

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

8-hour Ozone NAAQS. When the old 1-hour ozone NAAQS was replaced with the new, more stringent 8-hour standard, the Atlanta ozone nonattainment area was expanded in 2005 from its original 13 counties to 20 counties, and the Macon ozone nonattainment area (which includes Plant Scherer) was created. Litigation challenging implementation of the 1997 8-hour standard continues in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit), with a decision expected on most issues in the near future.

In March 2008, EPA issued a final rule further tightening the 8-hour standards. Based on this new rule, the Atlanta area has been re-classified to a more stringent nonattainment status. The Macon area has been designated as attainment, but the Georgia Environmental Protection Division recently

recommended that Bibb County, which includes Macon, along with several other counties, be designated as nonattainment under the 2008 standard. A state implementation plan (SIP) to bring the Atlanta area into attainment was due at the end of 2008, but is still under development. Implementation of certain aspects of the new standards is currently subject to ongoing rulemaking. The March 2008 ozone standard is one of several air quality rules being reviewed by the Obama administration which could be further revised.

Particulate Matter NAAQS. Plants Wansley and Scherer are in one of the areas designated in 2005 as nonattainment for the fine particulate matter standards first established in 1997. An implementation rule was finalized in 2007 setting forth how the 1997 standards are to be met, and a SIP for achieving 1997 standards in this area was due in 2008, but is still under development. Litigation on these EPA actions in the D.C. Circuit is continuing. While in 2006 the 1997 short-term standards for fine particulate matter were tightened, no new areas were designated in Georgia as nonattainment for the revised standards. On February 24, 2009, however, the D.C. Circuit remanded the 2006 long-term standards for fine particulate matter back to EPA for further review. Implementation of any standards for fine particulate matter that might be revised due to the remand will be the subject of future rulemaking.

Regional NO_X SIP Call. In 1998, EPA promulgated a regulation for a 22-state region, which includes Georgia, and a separate April 2004 rule, which imposed a cap on nitrogen oxides emissions in the affected region, required each state in such region to revise its SIP to implement the necessary reductions. In 2005, EPA stayed the implementation of that rule as it would apply to Georgia. In 2008, EPA finalized a rule which deletes Georgia from this regulation. North Carolina has challenged the rule in the D.C. Circuit, and the Georgia Coalition for Sound Environmental Policy, of which Oglethorpe is a member, has intervened in that litigation. Briefing had been underway. However, recently, the D.C. Circuit cancelled oral argument and requested additional briefing on remanding the case back to EPA instead.

Clean Air Interstate Rule. EPA finalized the Clean Air Interstate Rule (CAIR) in 2005 for ozone and fine particulate matter, which requires emissions reductions in sulfur dioxide and nitrogen oxides in most eastern states, including Georgia. The rule established a market-based cap and trade program, with emission caps for each affected state. Under Georgia's SIP, which now includes the rule, the caps would be implemented in two phases. The first phase, for nitrogen oxides caps, becomes effective in 2009 and, for sulfur dioxide caps, in 2010. A second phase for both pollutants follows in 2015. Pursuant to a challenge, the D.C. Circuit vacated the rule in its entirety, remanding it to EPA for further rulemaking consistent with the opinion. However, in a subsequent decision in response to petitions for rehearing, the Court decided to remand the rule to EPA without vacating it, therefore leaving it in place until EPA issues a new rule consistent with the Court's decision. As a result of the decision, more stringent regulatory limits could be imposed, or there may be a delay or acceleration in the effective dates of federal requirements to reduce emissions. Based on the D.C. Circuit's decision, EPA may not be able to use emissions trading or the surrender of Title IV sulfur dioxide allowances to achieve compliance, and may require sources to meet new, more stringent sulfur dioxide emission limitations instead. New standards will be the subject of future rulemaking.

Regional Haze. EPA's 1999 regional haze rule was created for the control of certain sources that emit nitrogen oxides or sulfur dioxide that contribute to the degradation of visibility in mandatory federal Class I areas, such as national parks and wilderness areas. A revised rule was issued in 2005 to address portions of the 1999 rule remanded to EPA. Another rule and guidance to implement the regional haze rule were also proposed by EPA in 2005. The goal of the regional haze rule is to restore natural visibility conditions in the Class I areas by 2064. Interim milestones reflecting reasonable progress towards this goal are required beginning in 2018. Moreover, the rule requires the application of best available retrofit technology for a certain class of sources (including Plants Scherer and Wansley) contributing to the impairment of visibility in the Class I areas. The Georgia SIP to

implement best available retrofit technology and reasonable further progress originally due in December 2007 has been submitted to EPA in draft form. That draft calls for no further controls for Plants Scherer or Wansley, but the SIP is still subject to EPA's review and approval.

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

Clean Air Mercury Rule and State-Related Mercury Rules. In 2005, EPA finalized a regulation that would control emissions of mercury, by creating a market-based cap-and-trade program that would reduce emissions of mercury in two phases, with the first phase becoming effective in 2010 and the second in 2018. In litigation challenging the rule, in early 2008, the D.C. Circuit vacated and remanded the cap-and-trade rule and a companion rule delisting electric generating units from the hazardous air pollutant source list in Section 112 of the Clean Air Act. Appeal of this decision to the U.S. Supreme Court was recently dismissed. While Georgia elected to include the EPA cap-and-trade program in its SIP, the outcome of this litigation is expected to negate that portion of Georgia's plan. Recently, EPA indicated its intent to conduct a rulemaking that would set maximum achievable control technology limits for certain hazardous air pollutants (that would include mercury) for coal and oil-fired electric generating units. Georgia's mercury rules include a "multi-pollutant rule" that requires operation of the existing selective catalytic reduction systems (nitrogen oxides) and scrubbers (sulfur dioxide and mercury) being installed at Plant Wansley as well as additional controls for mercury (activated carbon injection and baghouse), sulfur dioxide (scrubber) and nitrogen oxides (selective catalytic reduction system) at Plant Scherer. The maximum achievable control technology rulemaking for mercury and other hazardous air pollutants might affect current state rules like the multi-pollutant rule, and might require other rules or revisions to Georgia's SIP.

New Source Review. In November 1999, the United States Justice Department, on behalf of EPA, filed lawsuits against Georgia Power 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. We are not currently named in the lawsuits and we do not have an ownership interest in the named units of Plant Scherer. However, we can give no assurance that units in which we have 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 our responsibility for a share of any penalties and capital costs required to remedy our violations at co-owned facilities.

In December 2002 and October 2003, EPA promulgated revisions to its new source review rules. Petitions to review both of these final rules were filed with the D.C. 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 new source review. The October 2003 rule, which was intended to clarify the scope of the exclusion for routine maintenance and repair, was vacated by the court in March 2006. In October 2005, EPA also proposed a rule to clarify the test to be used for determining whether, following a change to a unit, an emissions increase would, for purposes of new source review, be deemed to occur. However, on December 10, 2008, EPA announced that it would not finalize that proposal.

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

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, we may have to incur

significant capital expenditures and increased operation expenses 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 Georgia Power. Any increases in Georgia Power's capital or operating expenses may cause an increase in the cost of power purchased from Georgia Power. (See "Our Members and Their Power Supply Resources—Member Power Supply Resources—Georgia Power Block Purchase.")

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

Congress continues to consider legislation, including climate-change legislation (including the recently introduced Waxman-Markey bill), that would amend the Clean Air Act or other federal statutes, many versions of which may impose new types of regulation or more stringent emissions limitations, including limits related to carbon dioxide emissions on power plants. Although there are many differences in these legislative proposals, most would impose caps on emissions of carbon dioxide at existing and future power plants that would increase in stringency over time. In addition to a cap-and-trade system, legislation could include a tax on carbon emissions and/or incentives to develop low-carbon technology. Congress may also consider other legislation with perceived greenhouse gas reduction benefits, such as a federal renewable energy portfolio standard. Emissions of carbon dioxide from our plants totaled approximately 13 million tons in 2008. The impact of any federal legislation would depend upon the specific requirements enacted and cannot be determined at this time.

Litigation related to carbon dioxide emissions continues on numerous fronts, and the outcome of such litigation could affect the power plants we own. In 2007, the U.S. Supreme Court ruled in Massachusetts v. EPA that certain greenhouse gases, including carbon dioxide, were pollutants which EPA has authority to regulate under the Clean Air Act, if EPA concludes regulation is needed to protect public health or welfare. The Court directed EPA to decide whether such regulation is needed. In response, EPA issued an advance notice of proposed rulemaking in July of 2008, seeking comment on whether EPA should undertake to regulate certain greenhouse gases under the Clean Air Act. Further, EPA recently announced a proposed rule that would require annual reporting of greenhouse gas emissions by many industries, including the electric utility industry, and by fossil fuel suppliers. Finally, EPA issued an "endangerment finding" regarding carbon dioxide that the Supreme Court indicated EPA had authority to make.

In another case, in 2004, Attorneys General from eight states and the Corporation Counsel of New York filed a complaint in the U.S. District Court for the Southern District of New York against Southern Company and four other electric power companies. The complaint alleges that the companies' emissions of carbon dioxide contribute to global warming, which the plaintiffs claim is a public nuisance. In September 2005, the Court granted the defendants' motions to dismiss, which the plaintiffs appealed in October 2005. The matter is now awaiting decision in the U.S. Court of Appeals for the Second Circuit. In a companion case to the Supreme Court matter in Massachusetts v. EPA, state, municipal and private parties filed a petition for review of EPA's failure to adopt regulations governing power plant emissions of carbon dioxide and other greenhouse gases under the Clean Air Act. In issuing a new final rule establishing updated New Source Performance Standards (NSPS) for steam generating units operated by electric utilities (and other industrial and commercial facilities), EPA took the position that it did not have the authority to set NSPS regulating these greenhouse gases under the Clean Air Act. EPA did not set a NSPS for carbon dioxide in the rule, relying on its findings prior to the Supreme Court case that it has no authority under the Clean Air Act to establish regulations that address climate change. Petitioners challenged the NSPS on numerous grounds, including that EPA

should have set a standard for carbon dioxide. After the Supreme Court reached its decision discussed above, the D.C. Circuit remanded the case back to EPA in September 2007 for further proceedings in light of that decision.

In June 2008, a Fulton County, Georgia Superior Court Judge overturned an air quality permit issued to Longleaf Energy Associates, LLC for the construction of a coal-fired power plant in Early County, Georgia. This permit had previously been upheld by the Office of State Administrative Hearings (OSAH) after an appeal by the Sierra Club and Friends of the Chattahoochee. The judgment set aside OSAH's decision on every issue raised on appeal, and concluded that carbon dioxide emissions are regulated under the Clean Air Act, an issue with the potential to bring the permitting of new air emission sources of any significant size in Georgia (including new electric generating plants we are currently considering) to a halt. Both Georgia and Longleaf appealed, and that ruling is currently under review by the Georgia Court of Appeals. We are participating as an amicus curiae in that appeal, and cannot at this time determine whether any ruling will ultimately impact the process of permitting new or modified sources in Georgia. Other ongoing litigation and administrative review actions are pending where, like the Georgia case, it is being argued that best available control technology is required for carbon dioxide emissions from new or modified sources under the Clean Air Act.

Other issues raised by global climate change are also being litigated in courts throughout the United States. For example, a current case in the United States District Court for the District of Columbia (Sierra Club v. USDA, et al.; No. 07-1860) is based on an argument that the consents or approvals issued by the Rural Utilities Service in its capacity as a lender for a coal-fired power plant constitute a major federal action and therefore triggers the environmental review requirements of the National Environmental Policy Act. Other litigation addresses the extent to which any reviewing federal agency must consider the impact of greenhouse gas emissions in the National Environmental Policy Act review process. We cannot currently predict how greenhouse gas emissions issues will arise in connection with pending or future permit proceedings or whether litigation based on climate change issues will adversely affect our construction and development plans.

While the outcome of these matters cannot be determined at this time, adverse results in one or more of these cases could result in substantial capital expenditures and/or increased operating costs at our fossil-fuel fired power plants (especially Plants Wansley and Scherer) and potentially impact the ability to permit new sources.

Coal combustion waste disposed in landfills and surface impoundments is currently a regulated solid waste that is exempt from hazardous waste regulations. As part of a 2000 regulatory determination, EPA is developing national solid waste management standards to address coal combustion waste and is continuing to consider whether coal combustion waste may continue to be classified as non-hazardous under the Resource Conservation and Recovery Act. The new standards will likely include increased groundwater monitoring, more stringent siting requirements and closure of existing coal waste management facilities not meeting minimum standards. Depending on the outcome of such rulemaking, which may occur in 2009, we may incur substantial additional costs for the management of these wastes.

Under the Clean Water Act, EPA and state environmental agencies are developing total maximum daily loads for certain impaired state waters. The establishment of total maximum daily loads 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 total maximum daily loads and the corresponding permit limitations that are established, the effects of such developments cannot be predicted at this time.

Since 2005, EPA has been carrying out a review of wastewater discharges from coal-fired power plants to determine whether new wastewater limitations are needed. In August 2008, EPA published an interim report on the status of the studies undertaken and the findings to date. Upon completion of the study in 2009, EPA will determine whether the current national effluent limitations guidelines for power plants need to be updated. Depending upon the outcome of this determination and any implementing actions by the State of Georgia, the wastewater permit limits at Plants Scherer and Wansley could be affected.

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

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

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

We are subject to the provisions of the Atomic Energy Act of 1954 (the Atomic Energy Act), which vests jurisdiction in the Nuclear Regulatory Commission over the construction and operation of nuclear reactors, particularly with regard to certain public health, safety and antitrust matters. The National Environmental Policy Act has been construed to expand the jurisdiction of the Nuclear Regulatory Commission to consider the environmental impact of a facility licensed under the Atomic Energy Act. Plants Hatch and Vogtle are being operated under licenses issued by the Nuclear Regulatory Commission. All aspects of the construction, operation and maintenance of nuclear power plants are regulated by the Commission. From time to time, new Commission regulations require changes in the design, operation and maintenance of existing nuclear reactors. Operating licenses issued by the Commission are subject to revocation, suspension or modification, and the operation of a nuclear unit may be suspended if the Commission determines that the public interest, health or safety so requires. The operating licenses issued for each unit of Plants Hatch and Vogtle expire in 2034 and 2038 and 2047 and 2049, respectively.

Applications have been filed with the Nuclear Regulatory Commission for an early site permit and for combined construction permits and operating licenses that would allow the construction and operation of two additional units at Plant Vogtle. See "Business Overview—Future Power Resources."

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

Contracts with the Department of Energy have been executed to provide for the permanent disposal of spent nuclear fuel produced at Plants Hatch and Vogtle. The Department of Energy failed to begin disposing of spent fuel in 1998 as required by the contracts, and Georgia Power, as agent for the co-owners of the plants, is pursuing legal remedies against the Department of Energy for breach of contract. See Note 1 of Notes to Audited Consolidated Financial Statements for information regarding the outcome of this litigation.

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

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

We are subject to the provisions of the Federal Power Act applicable to licensees with respect to their hydroelectric developments. Rocky Mountain is a hydroelectric project subject to licensing by the Federal Energy Regulatory Commission.

We have a license, expiring in 2027, for Rocky Mountain. See "Properties—Generating Facilities" for additional information.

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

The Energy Policy Act of 2005 amended the Federal Power Act to authorize the Federal Energy Regulatory Commission to establish regional reliability organizations authorized to enforce reliability standards and to establish clear responsibility for the commission to prohibit manipulative energy

trading practices. As a generation owner and participant in wholesale power transactions, we could be subject to penalties for violation of these standards and regulations.

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

The following table sets forth certain operating performance information of each of our generating facilities (excluding Heard, which we acquired on April 30, 2009):

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.

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 March 31, 2009, we had a 78-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 March 31, 2009, our coal stockpile at Plant Scherer contained a 73-day supply based on continuous operation. Plant Scherer burns sub-bituminous coal purchased from coal mines in the Powder River Basin in Wyoming.

We separately dispatch Plant Wansley and Plant Scherer, but use Georgia Power as our agent for fuel procurement. We currently lease approximately 1,200 rail cars to transport coal to these two facilities.

For information relating to the impact that the Clean Air Act may have on our coal-fired facilities, see "Environmental and Other Regulation—Clean Air Act."

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

Natural Gas. We purchase the natural gas, including transportation and other related services, needed to operate Doyle, Talbot, Chattahoochee, and Heard and the combustion turbines owned by Hartwell. We purchase natural gas in the spot market and under agreements at indexed prices. We have entered into hedge agreements to manage a portion of our exposure to fluctuations in the market price of natural gas. We manage exposure to such risks only with respect to members that elect to receive such services. We purchase transportation under long-term firm and short-term firm and non-firm contracts. We have also contracted with Petal Gas Storage, LLC to provide 800,000 MMbtus of firm natural gas storage services and related firm transportation. (See "QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK—Commodity Price Risk.")

Plants Hatch, Vogtle, Wansley and Scherer Units No. 1 and No. 2 are co-owned by Georgia Power, the Municipal Electric Authority of Georgia, the City of Dalton and us, and Rocky Mountain is co-owned by Georgia Power and us. Each such co-owner owns or leases undivided interests in the amounts shown in the following table (which excludes the Plant Wansley combustion turbine). We are the operating agent for Rocky Mountain. Georgia Power is the operating agent for each of the other plants.

Georgia Power is a wholly owned subsidiary of The Southern Company and is engaged primarily in the generation and purchase of electric energy and the transmission, distribution and sale of this energy. Georgia Power distributes and sells energy within the State of Georgia at retail in over 600 communities (including Athens, Atlanta, Augusta, Columbus, Macon, Rome and Valdosta), as well as in rural areas, and at wholesale to some of our members, The Municipal Electric Authority of Georgia and two municipalities. Georgia Power is the largest supplier of electric energy in the State of Georgia. (See "Business Overview—Relationship with Georgia Power.") Georgia Power is subject to the informational requirements of the Exchange Act, and, in accordance therewith, files reports and other information with the SEC.

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

Dalton Utilities is a combined utility that provides electric, gas, water and wastewater services to the city of Dalton (located in northwest Georgia) and some of the surrounding communities. It presently serves more than 65,000 residential, commercial and industrial electric customers.

Our rights and obligations with respect to Plants Hatch, Wansley, Vogtle and Scherer are contained in a number of contracts between Georgia Power and us and, in some instances, MEAG Power and the City of Dalton. We are a party to four Purchase and Ownership Participation Agreements (Ownership Agreements) under which we acquired from Georgia Power a 30% undivided interest in each of Plants Hatch, Wansley and Vogtle, a 60% undivided interest in Scherer Units No. 1 and No. 2 and a 30% undivided interest in those facilities at Plant Scherer intended to be used in common by Scherer Units No. 1, No. 2, No. 3 and No. 4 (the Scherer Common Facilities). We have also entered into four Operating Agreements (Operating Agreements) relating to the operation and maintenance of Plants Hatch, Wansley, Vogtle and Scherer, respectively. The Ownership Agreements and Operating Agreements relating to Plants Hatch and Wansley are two-party agreements between Georgia Power and us. The Ownership Agreements and Operating Agreements relating to Plants Vogtle and Scherer are agreements among Georgia Power, MEAG Power, the City of Dalton and us. The parties to each Ownership Agreement and Operating Agreement are referred to as "participants" with respect to each such agreement.

In 1985, in four transactions, we sold our entire 60% undivided ownership interest in Scherer Unit No. 2 to four separate owner trusts established by institutional investors. We retained all of our rights and obligations as a participant under the Ownership and Operating Agreements relating to Scherer Unit No. 2 for the term of the leases. Our leases expire in 2013, with options to renew for a total of 8.5 years. We also have fair market value purchase options at specified dates, including 2013 and the end of lease renewal terms. We treat these transactions as capital leases for financial reporting purposes. (See Note 4 of Notes to Audited Consolidated Financial Statements.) (In the following

discussion, references to participants "owning" a specified percentage of interests include our rights as a deemed owner with respect to our leased interests in Scherer Unit No. 2.)

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

Under the Ownership Agreements, we are obligated to pay a percentage of capital costs of the respective plants, as incurred, equal to the percentage interest which we own or lease at each plant. Georgia Power 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 Georgia Power and to substitute alternative capital budgets. Georgia Power 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 Georgia Power to contract with a third party for the operation of the nuclear units. In March 1997, Georgia Power designated Southern Nuclear Operating Company as the operator of Plants Hatch and Vogtle, pursuant to the Nuclear Operating Agreement between Georgia Power and Southern Nuclear Operating Company, which the co-owners had previously approved. In connection with the amendments to the Plant Scherer Ownership and Operating Agreements, the co-owners of Plant Scherer entered into the Plant Scherer Managing Board Agreement which provides for a managing board to coordinate the implementation and administration of the Plant Scherer Ownership and Operating Agreements and provides for increased rights for the co-owners regarding certain decisions, but does not alter Georgia Power's role as agent with respect to Plant Scherer.

The Operating Agreements provide that we are entitled to a percentage of the net capacity and net energy output of each plant or unit equal to our percentage undivided interest owned or leased in such plant or unit. Georgia Power, as agent, schedules and dispatches Plants Hatch and Vogtle. The Plant Scherer and Wansley ownership and operating agreements allow each co-owner (i) to dispatch separately its respective ownership interest in conjunction with contracting separately for long-term coal purchases procured by Georgia Power and (ii) to procure separately long-term coal purchases. We separately dispatch our ownership share of Scherer Units No. 1 and No. 2 and of Plant Wansley.

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

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

The Operating Agreement for Plant Hatch will remain in effect with respect to Hatch Units No. 1 and No. 2 until 2009 and 2012, respectively. We have entered into an agreement with Georgia Power, subject to Rural Utilities Service approval, to extend the Operating Agreement for so long as an Nuclear Regulatory Commission 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, Georgia Power will retain such powers as are necessary in connection with the disposition of the property of the applicable plant, and the rights and obligations of the parties shall continue with respect to actions and expenses taken or incurred in connection with such disposition.

In conjunction with the development of additional units at Plant Vogtle (see "Business Overview—Our Power Supply Resources—Future Power Resources"), Georgia Power, MEAG Power, the City of Dalton and us entered into amendments to the Operating Agreement for Plant Vogtle and the Nuclear Managing Board Agreement, and entered into an Ownership Agreement that governs participation in Vogtle Units No. 3 and No. 4.

We own a 74.61% undivided interest in Rocky Mountain and Georgia Power owns the remaining 25.39% undivided interest.

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

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

In late 1996 and early 1997, we completed lease transactions for our 74.61% undivided ownership interest in Rocky Mountain. Under the terms of these transactions, we leased the facility to three institutional investors for the useful life of the facility, who in turn leased it back to us for a term of 30 years. We will continue to control and operate Rocky Mountain during the leaseback term. For more information about the structure of these lease transactions, see "MANAGEMENT'S DISCUSSION

AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Financial Condition—Off-Balance Sheet Arrangements-Rocky Mountain Lease Arrangements."

We have an agreement with Doyle I LLC, a limited liability company owned by one of our members, Walton Electric Membership Corporation, to purchase the output of a gas-fired combustion turbine generating facility with a nominal contract rating of 325 megawatts over a 15-year term. Delivery commenced May 15, 2000.

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

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

We have an option to purchase the facility at the end of the term of the agreement at a fixed price. We treat this agreement as a capital lease of the facility for financial reporting purposes (see Note 4 of Notes to Audited Consolidated Financial Statements).

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

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS

We are a not-for-profit electric cooperative whose principal business is providing wholesale electric service to our 38 members. Consequently, substantially all of our revenues and cash flow are derived from sales to our members pursuant to long-term, take-or-pay wholesale power contracts that extend through 2050. These contracts obligate our members jointly and severally to pay all of our costs and expenses associated with owning and operating our power supply business. To that end, our existing rate structure provides for a pass-through of actual energy costs. Charges for fixed costs, including capacity, other non-energy charges, debt service obligations and the margin required to meet our margins for interest ratio rate covenant under the indenture are carefully managed throughout the year to ensure that sufficient capacity-related revenues are produced. This structure provides us with the ability to manage our revenues to assure full recovery of our costs in rates and to consistently meet our financial obligations since our formation in 1974.

Despite the unprecedented instability in the global financial markets and the recession in the overall economy, we continue to be well positioned, both financially and operationally, to fulfill our obligations to our members, bondholders and creditors. In this regard, our revenues in 2008 were sufficient to recover all of our costs and to satisfy all of our debt service obligations and financial covenants, including the annual margin required to meet the margins for interest ratio rate covenant under the indenture. Specifically, we recorded a net margin of $19.3 million in 2008, which met the required margins for interest ratio of 1.10. Furthermore, our board of directors believes that it is important to improve our coverage ratios in light of current financial market conditions and an anticipated period of increased capital requirements, as noted below. Consequently, for the first time since our margins for interest ratio rate covenant was instituted in 1997, we are targeting higher margins than what would otherwise be necessary to meet the minimum required margins for interest ratio of 1.10 under the indenture. For 2009, we are collecting revenues sufficient to achieve a margins for interest ratio of 1.12, effectively increasing our annual margin target by 20%. In this regard, we recorded net margins of $15.6 million during the three months ended March 31, 2009 as compared to net margins of $6.7 million during the same period of the prior year, a 133% increase over the prior period; for a discussion regarding the basis of this increase, see "Results of Operations—Net Margins." Our board of directors will evaluate coverage ratios throughout the period of anticipated construction and may choose to increase or decrease margins for interest coverage in the future.

We maintain a strong liquidity position despite the disruption in the global financial markets. At March 31, 2009, we had $964 million of unrestricted available liquidity. Our liquidity is comprised of a diversified, cost-effective mix of cash (including short-term investments), committed lines of credit and a commercial paper program.

The value of our liquidity position was realized throughout 2008 as the financial markets experienced substantial turmoil. In particular, the use of our commercial paper program and a line of credit permitted us to refinance certain insured variable rate demand bonds that we had previously issued in a systematic, cost-effective manner. These variable rate demand bonds were unable to be remarketed due to bond insurer downgrades and, as a result, carried significantly higher rates of interest. For a detailed discussion of how the negative events in the capital markets impacted us, see "Financial Condition—Negative Events in the Capital Markets."

Over the last several years, we have focused our efforts on developing a menu of generation options that offers members more ownership and control over their generation resources (through us) in order to help mitigate reliance on third-party contracts. In furtherance of these efforts, we have taken the following actions:

In addition, we forecast that expenditures required for existing generating facilities will be approximately $672 million over the next three years. These expenditures include normal additions and replacements to plant in-service and projects to maintain and achieve compliance with current and anticipated environmental requirements. Importantly, this forecast does not include additional capital expenditures or increased operational expenses for Plants Wansley and Scherer due to climate change legislation and regulation which is likely to be enacted or adopted in the future.

We will remain focused on providing reliable, cost-effective energy to our members and the 4.1 million people they serve. There are, nevertheless, certain risks and challenges that must be overcome including:

To provide reliable, cost-effective energy to our members and their consumers, and navigate these risks, we intend to continue to do what we have done successfully for the last 35 years, including, among other things:

We operate on a not-for-profit basis and, accordingly, seek only to generate revenues sufficient to recover our cost of service and to generate margins sufficient to establish reasonable reserves and meet certain financial coverage requirements. Revenues in excess of current period costs in any year are designated as net margin in our statements of revenues and expenses. Retained net margins are designated on our balance sheets as patronage capital, which is allocated to each of our members on the basis of its fixed percentage capacity costs responsibilities in our generation and purchased power resources. Since our formation in 1974, we have generated a positive net margin in each year and had a balance of $551 million in patronage capital as of March 31, 2009.

Patronage capital constitutes our principal equity. Any distributions of patronage capital are subject to the discretion of our board of directors. However, under the indenture, we are prohibited from making any distribution of patronage capital to our members if, at the time of or after giving effect to the distribution, (i) an event of default exists under the indenture, (ii) our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities, or (iii) the aggregate amount expended for distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after such date. This last restriction, however, will not apply if, after giving effect to such distribution, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our total long term debt and equities.

Pursuant to the wholesale power contracts between us and each of our members, we are required to design capacity and energy rates that generate sufficient revenues to recover all costs, including the payments of principal and interest on our indebtedness, to establish and maintain reasonable margins and to meet our financial coverage requirements. We review our capacity rates frequently throughout the year to ensure that net margin goals are met, and are required to do so at least once annually.

The rate schedule under the wholesale power contracts implements on a long-term basis the assignment to each member of responsibility for our fixed costs. The monthly charges for capacity and other non-energy charges are based on a rate formula using our budget. Our 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 indenture, we are required, subject to any necessary regulatory approval, to establish and collect rates that are reasonably expected, together with our other revenues, to yield a margins for interest ratio for each fiscal year equal to at least 1.10. The margins for interest ratio is determined by dividing margins for interest by interest charges. Margins for interest equal the sum of (i) our net margins (after certain defined adjustments), (ii) interest charges and (iii) any amount included in net margins for accruals for federal or state income taxes. The definition of margins for interest takes into account any item of net margin, loss, gain or expenditure of any of our affiliates or subsidiaries only if we have received such net margins or gains as a dividend or other distribution from such affiliate or subsidiary or if we have made a payment with respect to such losses or expenditures.

The rate schedule also includes a prior period adjustment mechanism designed to ensure that we achieve the minimum 1.10 margins for interest ratio. Amounts, if any, by which we fail to achieve a minimum 1.10 margins for interest ratio would be accrued as of December 31 of the applicable year and collected from our members during the period April through December of the following year. The rate schedule formula is intended to provide for the collection of revenues which, together with

revenues from all other sources, are equal to all costs and expenses we record, plus amounts necessary to achieve at least the minimum 1.10 margins for interest ratio.

For 2008, 2007 and 2006, we achieved a margins for interest ratio of 1.10. To enhance financial coverage during an anticipated period of generation construction, our 2009 budget, approved by our board of directors, includes a 1.12 margins for interest ratio. The board of directors will evaluate coverage ratios throughout the period of anticipated construction and may choose to increase or decrease margins for interest coverage in the future.

We follow generally accepted accounting principles in the United States and the practices prescribed in the Uniform System of Accounts of the Federal Energy Regulatory Commission as modified and adopted by the Rural Utilities Service.

We have determined that the following accounting policy is important to understanding the presentation of our financial condition and results of operations and requires our management to make estimates and assumptions about matters that were uncertain at the time of preparation of our financial statements. Changes in these estimates and assumptions by our management could materially impact our results of operations and financial condition. Our management has discussed the development, selection and disclosure of critical accounting policies and estimates with the audit committee of our board of directors.

We are 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 us to record regulatory assets and regulatory liabilities to reflect future cost recovery or refunds that we have a right to pass through to our members. At December 31, 2008, our regulatory assets and liabilities totaled $389 million and $110 million, respectively. (See Note 1 of Notes to Audited Consolidated Financial Statements.) While we do not currently foresee any events such as competition or other factors that would make it not probable that we will recover these costs from our members as future revenues through rates under our wholesale power contracts, if such an event were to occur, we could no longer apply the provisions of SFAS No. 71, which would require us to eliminate all regulatory assets and liabilities that had been recognized as a charge to our statement of revenues and expenses and begin recognizing assets and liabilities in a manner similar to other businesses in general. In addition, we would be required to determine any impairment to other assets, including plants, and write-down those assets, if impaired, to their fair value.

In April 2009, the Financial Accounting Standards Board (FASB) issued Staff Position No. 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly" (FSP 157-4). FSP 157-4 emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique and inputs used, the objective for the fair

value measurement is unchanged from what it would be if markets were operating at normal activity levels or transactions were orderly; that is, to determine the current exit price. FSP 157-4 sets forth additional factors that should be considered to determine whether there has been a significant decrease in the volume and level of activity when compared with normal market activity. The reporting entity shall evaluate the significance and relevance of the factors to determine whether, based on the weight of evidence, there has been a significant decrease in activity and volume. FSP 157-4 indicates that if an entity determines that either the volume or level of activity for an asset or liability has significantly decreased (from normal conditions for that asset or liability) or price quotations or observable inputs are not associated with orderly transactions, increased analysis and management judgment will be required to estimate fair value. FSP 157-4 further notes that a fair value measurement should include a risk adjustment to reflect the amount market participants would demand because of the risk (uncertainty) in the cash flows.

FSP 157-4 also requires a reporting entity to make additional disclosures in interim and annual periods. FSP 157-4 is effective for interim periods ending after June 15, 2009, with early application permitted for periods ending after March 15, 2009. Revisions resulting from a change in valuation techniques or their application are accounted for as a change in accounting estimate. Currently, the adoption of FSP 157-4 is not expected to have a material effect on our results of operations, cash flows or financial condition.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, "Interim Disclosures about Fair Value of Financial Instruments" (FSP FAS 107-1 and APB 28-1). FSP FAS 107-1 and APB 28-1 require disclosures about fair value of financial instruments in interim and annual financial statements. FSP FAS 107-1 and APB 28-1 are effective for periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Currently, the adoption of FSP 107-1 and APB 28-1 are not expected to have a material effect on our results of operations, cash flows or financial condition.

We adopted SFAS No. 141 (revised 2007) "Business Combinations" issued by the FASB December 2007 effective January 1, 2009. SFAS No. 141(r) establishes principles and requirements for how the acquirer in a business combination: a) recognizes and measures the identifiable assets acquired, liabilities assumed, and noncontrolling interest in acquiree; b) recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; c) determines what information to disclose to enable users of financial statements to evaluate the nature and financial effects of the business combination. The adoption of SFAS No. 141(r) did not have a material affect on our results of operations, cash flows or financial condition.

In November 2007, the FASB issued a one-year deferral for the implementation of Statement of Financial Accounting Standards No. 157 "Fair Value Measurements" (SFAS No. 157) for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The deferral was applicable for asset retirement obligations measured at fair value upon initial recognition under FASB Statement No. 143 "Accounting for Asset Retirement Obligations", or upon a remeasurement event. We adopted SFAS No. 157 for non-financial assets and non-financial liabilities effective January 1, 2009 with no material effect on its results of operations, cash flows or financial condition.

Sales to Members. We generate revenues principally from the sale of electric capacity and energy.

Our operating revenues fluctuate from period to period based on factors including weather and other seasonal factors, load growth in the service territories of our members, operating costs, availability of electric generation resources, our decisions of whether to dispatch our owned or purchased resources or member-owned resources over which we have dispatch rights and by members' decisions of whether to purchase a portion of their hourly energy requirements from our resources or from other suppliers.

Total revenues from sales to members were 3.3% lower in the three-month period ended March 31, 2009 than such revenues for the same period of 2008. Total revenues from sales to members increased by 7.7% for 2008 compared to 2007 and increased 2.0% for 2007 compared to 2006. The components of member revenues were as follows:

Capacity revenues relate primarily to the assignment to each of the members of the fixed costs, including fixed production expenses, depreciation and amortization expenses and interest charges associated with our business. Each member is required to pay us for capacity furnished under its wholesale power contract in accordance with rates we establish.

Capacity revenues for the three-month period ended March 31, 2009 increased 9.0% compared to the same period for 2008. The increase in capacity revenues for the three-months ended March 31, 2009 compared to March 31, 2008 is primarily due to higher budgeted interest expense on long-term debt relating to an expected increase in debt levels resulting from generation facility construction. In addition, higher net margins due to both an increase in budgeted interest expense upon which margins for interest is calculated off of and due to an increase in the margins for interest target to 1.12 in 2009 compared to a margins for interest target of 1.10 in 2008, contributed to an increase in capacity revenues in this period.

Capacity revenues from members increased 5.7% in 2008 compared to 2007 and decreased 1.5% in 2007 compared to 2006. The increase in capacity revenues in 2008 as compared to 2007 resulted from higher collections from members due to increases in fixed production expenses resulting from (1) the $22.7 million reversal of the Monroe County property tax reserve in 2007 due to a favorable settlement; there was no corresponding reversal in 2008, (2) an increase in staffing at Plants Hatch and Vogtle and (3) an increase in administrative and general expenses. Also, lower investment income from cash and temporary cash investments in the amount of $12.7 million in 2008 as compared to 2007 contributed to an increase in capacity collections from members in 2008. The increase in capacity revenues associated with production expenses and investment income was offset somewhat by a full year of Vogtle depreciation deferral in the amount of $28.6 million for 2008 as compared to a half year deferral in 2007 in the amount of $14.3 million. For further discussion regarding depreciation and amortization,

see "Operating Expenses"; for further discussions on investment income, see "Other Income"; and see Note 13 of Notes to Audited Consolidated Financial Statements for further information regarding the Monroe County property tax litigation reserve reversal. For 2007 as compared to 2006, capacity revenues reflected lower collections from members of $36.8 million related to lower Plant Vogtle depreciation and amortization expense and the reversal of the Monroe County property tax litigation reserve discussed above. In addition, capacity revenues for 2007 compared to 2006 were reduced by $5.1 million due to expiration of the Georgia Power purchased power agreement effective March 31, 2006. For 2006, capacity revenues reflected reduced collections from members of $29.3 million. The reduced revenue collection was related to a gain on the sale of sulfur dioxide allowances. See Note 10 of Notes to Audited Consolidated Financial Statements for further discussion regarding the sale of sulfur dioxide allowances.

Energy revenues relate primarily to the pass-through to the members of the variable costs, such as actual fuel costs, variable operation and maintenance costs and purchased energy costs, associated with our business. Each member is required to pay us for energy furnished under its wholesale power contract in accordance with rates we establish.

Energy revenues for the three-month period ended March 31, 2009 decreased 16.4% compared to the same period for 2008. Our average energy revenue per megawatt-hour from sales to our members was 7.4% lower for the three-month period ended March 31, 2009 as compared to the same period of 2008. The decrease in energy revenues for the three-month period ended March 31, 2009 compared to the same period of 2008 was primarily due to the pass-through to our members of lower fuel costs (primarily due to lower coal-fired generation) and lower purchased power energy costs (primarily due to the lower volume of purchased megawatt-hours). For a discussion of fuel costs and purchased power costs, see "Operating Expenses."

Energy revenues from members increased 9.5% in 2008 compared to 2007 and increased 5.5% in 2007 compared to 2006. The increase in energy revenues for 2008 was primarily due to the pass-through of higher fuel costs associated with increased generation at Plants Scherer and Wansley. Energy revenues increased in 2007 as compared to 2006 partly due to higher fuel costs and partly due to higher variable operation and maintenance costs, offset somewhat by the pass-through to members of lower purchased power energy costs. See "Operating Expenses" for further discussion for the changes in fuel costs, variable operation and maintenance costs and purchased power energy costs.

The following table summarizes the amounts of kilowatt-hours sold to members and average revenues per kilowatt-hour during the three-month periods ended March 31, 2009 and March 31, 2008 and for the year ended for each of the past three years:

The total number of kilowatt-hours sold to members for the three-month period ended March 31, 2009 decreased 9.7% compared to the same period for 2008. The average revenue per kilowatt-hour from sales to members increased 7.1% for the three-month period ended March 31, 2009 compared to the same period for 2008.

In 2008 compared to 2007, kilowatt-hour sales to members increased 2.2% and in 2007 as compared to 2006 kilowatt-hour sales to members decreased 0.9%. The average revenue per kilowatt-hour from sales to members increased 5.4% for 2008 compared to 2007 and increased 2.9%

for 2007 compared to 2006. Increases in kilowatt-hours of generation and kilowatt-hours of purchased power were the reason for increased kilowatt-hours sold to members for 2008. The expiration of an agreement to purchase capacity and energy from Georgia Power was the primary reason for the decrease in kilowatt hours sold to members in 2007. For further discussions regarding fuel and purchased power costs, see "Operating Expenses."

We pass through actual energy costs to our members such that energy revenues equal energy costs. The energy portion of member revenues per kilowatt-hour increased 7.2% in 2008 as compared to 2007 and increased 6.5% in 2007 compared to 2006. The increase in average revenues per kilowatt-hour in 2008 compared to 2007 is primarily due to the pass-through of higher fuel costs. The increase in average energy revenues per kilowatt-hour in 2007 compared to 2006 is primarily due to the pass-through of higher fuel costs and higher variable operation and maintenance expenses. For further discussion regarding fuel costs and variable operation and maintenance expenses, see "Operating Expenses."

Operating expenses for the three-month period ended March 31, 2009 decreased 8.0% compared to the same period of 2008. The decrease in operating expenses for the three-month period ended March 31, 2009 compared to the same period of 2008 was primarily due to lower fuel costs and lower purchased power costs.

Our operating expenses (excluding the 2008, 2007 and 2006 gains related to the sale of sulfur dioxide allowances of $0.3 million, $0.4 million and $39.5 million, respectively) increased 8.0% in 2008 compared to 2007 and were 1.8% lower in 2007 compared to 2006. In 2008, increases in fuel and production costs were offset somewhat by decreases in deprecation and amortization and in accretion expenses. For 2007, the primary drivers for the decrease in operating expenses were decreases in production, and depreciation and amortization expenses offset somewhat by an increase in fuel costs.

For the three-month period ended March 31, 2009 compared to the same period of 2008, total fuel costs decreased 10.4% while total generation decreased 7.4%. Average fuel costs per kilowatt-hour decreased 3.2% for the three-month period ended March 31, 2009 compared to the same period of 2008. This decrease in total fuel costs resulted primarily from lower coal-fired generation at Plants Scherer and Wansley, offset somewhat by higher generation at the natural gas-fired Chattahoochee energy facility. The decrease in average fuel costs during the first quarter of 2009 compared to the same quarter of 2008 resulted primarily from a 29.1% decrease in generation at Plants Scherer and Wansley due to scheduled outages at both Plants Scherer and Wansley whereas last year there was only a scheduled outage at Plant Wansley. Coal-fired generation has a higher average cost per megawatt-hour of generation as compared to nuclear generation. Natural gas-fired generation at the Chattahoochee energy facility increased 117.3%, or 319,000 megawatt-hours, primarily due to a substantial decline in the price of natural gas; the average fuel cost per megawatt-hour of natural gas-fired generation at Chattahoochee decreased 49.4% in the first quarter of 2009 from levels a year ago.

Total fuel costs increased 12.3% in 2008 compared to 2007 and increased 11.0% in 2007 as compared to 2006 while total generation increased 2.0% and 0.8%, respectively. Average fuel cost per kilowatt-hour increased 10.1% in 2008 compared to 2007 and 10.0% in 2007 compared to 2006. The increase in total and average fuel costs for 2008 as compared to 2007 resulted primarily from an 8.4% increase in higher cost coal-fired generation at Plants Scherer and Wansley. Coal-fired generation has a higher average cost per kilowatt-hour of generation as compared to nuclear generation. For 2007 as compared to 2006, the increase in total and average fuel cost resulted primarily from a change in the mix of generation with increased generation of 572,000,000 kilowatt-hours, a 49.7% increase, from higher priced gas-fired facilities offset somewhat by lower generation from coal-fired facilities which has a lower average price than gas-fired generation.

Production expenses increased 12.5% in 2008 compared to 2007 and decreased 3.1% in 2007 as compared to 2006. For 2008 as compared to 2007, the increase in production expenses resulted primarily from (1) the $22.7 million reversal of the Monroe County property tax reserve in 2007 due to a favorable settlement; there was no corresponding reversal in 2008, (2) increase staffing at Plants Hatch and Vogtle in response to new fitness for duty regulations impacting operations, maintenance and security departments at nuclear facilities and (3) increase in administrative and general expenses partly due to increased staffing levels and higher wages, payroll taxes and health benefits. The increase in administrative and general was also partly due to a carbon capture research project administered through the Electric Power Research Institute. The decrease in production expenses in 2007 as compared to 2006 primarily resulted from the reversal of the Monroe County property tax litigation reserve in the amount of $22.7 million due to a favorable ruling from the Georgia Supreme Court as discussed in Note 13 of Notes to Audited Consolidated Financial Statements. This decrease was offset somewhat by higher variable operation and maintenance expenses resulting primarily from increased amortization for deferred nuclear refueling outage costs and for deferred outage costs associated with fossil fuel facilities. The increase in nuclear refueling outage amortization resulted partly from higher outage costs (and thus higher amortization) at Plant Vogtle due to a pressurized weld overlay project mandated by the Nuclear Regulatory Commission and partly due to an increase in outage costs at Hatch Unit No. 1 due to transformer replacement expenses.

Total purchased power costs decreased 30.9% for the three-month period ended March 31, 2009 compared to the same period of 2008. Purchased megawatt-hours decreased 61.8% for the three months ended March 31, 2009 compared to the same period of 2008. The average cost per megawatt-hour of total purchased power increased 80.8% for the three months ended March 31, 2009 compared to the same period of 2008. Purchased power costs increased 3.3% in 2008 as compared to 2007 and decreased 13.5% in 2007 compared to 2006 as follows:

Purchased power capacity costs remained relatively unchanged in the three-month period of 2009 compared to the same period of 2008. The increase in purchased power capacity costs for 2008 as compared to 2007 was primarily due to an increase in the costs of services provided by Georgia System Operations under various agreements with us. The decrease in purchased power capacity costs for 2007 compared to 2006 was due to the expiration of the Georgia Power purchased power agreement effective March 31, 2006 as discussed in more detail below.

Purchased power energy costs for the three-month period ended March 31, 2009 decreased 44.8% compared to the same period of 2008. The average cost of purchased power energy increased 44.6% for the three-month period ended March 31, 2009 compared to the same period of 2008. The decreases in purchased power energy costs and in the volume of purchased megawatt-hours along with the increase in the cost per megawatt-hour were all primarily due to the expiration of the Morgan Stanley purchased power agreement effective December 31, 2008.

Purchased power energy costs increased 2.7% in 2008 compared to 2007 and decreased 14.5% in 2007 compared to 2006. Purchased kilowatt-hours increased 10.1% in 2008 compared to 2007 and decreased 24.4% for 2007 compared to 2006. The average cost of purchased power energy per kilowatt-hour decreased 6.8% in 2008 compared to 2007 and increased 13.1% in 2007 compared to

2006. The decrease in the cost per kilowatt-hour of purchased power energy in 2008 as compared to 2007 was primarily due to increased kilowatt-hours acquired under our energy replacement program, which replaces power from our generation facilities with lower price spot market purchased power, and by an increase in kilowatt-hours acquired under a purchased power agreement with Morgan Stanley which expired December 31, 2008. This increase was offset somewhat by reduced purchases of higher priced kilowatt-hours under a purchased power agreement with Hartwell. The decrease in purchased power energy costs for 2007 compared to 2006 resulted primarily from the decrease in kilowatt-hours purchased, which resulted partly from the termination of the Georgia Power agreement effective March 31, 2006. The expiration of the Georgia Power purchased power agreement with its favorable energy cost to us was primarily the reason for the increase in average energy cost per kilowatt-hour in 2007 as compared to 2006. The decrease in kilowatt-hours acquired under our energy replacement program also contributed to the decrease in purchased power energy costs and volume of purchased power kilowatt-hours in 2007 as compared to 2006. The decrease in kilowatt-hours purchased and energy costs from the reasons noted above were offset somewhat by an increase in kilowatt-hours purchased and energy cost acquired under several other purchased power agreements.

Purchased power expenses for the years 2006 through 2008 include the cost of capacity and energy purchases under various long-term power purchase agreements. Our capacity and energy expenses under these agreements amounted to approximately $84 million in 2008, $89 million in 2007 and $103 million in 2006. For a discussion of the power purchase agreements, see Note 9 of Notes to Audited Consolidated Financial Statements.

Depreciation and amortization expense decreased 9.0% in 2008 compared to 2007 and decreased 16.2% in 2007 as compared to 2006. Depreciation and amortization expense decreased in 2008 compared to 2007 primarily due to the deferral of $28.6 million in depreciation and amortization expense at Plant Vogtle in 2008 compared to a $14.3 million deferral of depreciation and amortization expense in 2007. The decrease in depreciation and amortization expense for 2007 as compared to 2006 is partly attributable to lower depreciation expenses for Plant Vogtle of $14.3 million. In June 2007, Georgia Power, as agents for the co-owners, filed an application with the Nuclear Regulatory Commission to extend the licenses for Vogtle Unit No. 1 and Unit No. 2 for an additional 20 years. Effective July 1, 2007, under the provisions of SFAS No. 71, we began deferring the difference between Plant Vogtle depreciation expense based on the current 40-year operating license versus depreciation expense based on the applied for 20-year license extension. The deferral amount will be amortized into deprecation expense over the remaining life of Plant Vogtle beginning in the year that the license extension is approved by the Nuclear Regulatory Commission. We received approval on June 3, 2009. In addition, the lower depreciation and amortization expense in 2007 compared to 2006 resulted from $10.2 million in accelerated amortization of deferred amortization of capital leases in 2006, as discussed below in accretion expense. This accelerated amortization in 2006 was offset somewhat by lower depreciation expenses for nuclear and coal-fired facilities due to adoption of lower composite depreciation rates effective January 1, 2006, approved by the Rural Utilities Service and supported by a depreciation study performed in 2005.

Accretion expense totaled $17.1 million in 2008, $16.2 million in 2007 and $17.4 million in 2006. The accretion expense recognized under SFAS No. 143, "Accounting for Asset Retirement Obligations," primarily relates to our nuclear generation facilities.

During 2006, we sold sulfur dioxide allowances in excess of our needs to various parties and received approximately $39.5 million in net proceeds from these sales. The proceeds from the sales of sulfur dioxide allowances are included in the statements of revenues and expenses under "Operating Expenses" in the line item "Other." The proceeds received from sale of sulfur dioxide allowances was offset, however, by a $29.3 million reduction in sales to members and by $10.2 million in accelerated amortization of deferred amortization of capital leases in 2006.

Investment income decreased 15.4% (or $1.4 million) in the three-month period ended March 31, 2009 compared to the same period of 2008. The decrease for the three months ended March 31, 2009 compared to the same period of 2008 resulted primarily from realized losses sustained in the decommissioning trust funds. The income (loss) from investments in our external and internal decommissioning funds for the periods ended March 31, 2009 and 2008 totaled ($3.3) million and $2.9 million, respectively. For nuclear decommissioning, we record a regulatory asset or liability for the timing difference in accretion expense recognized under SFAS No. 143, "Accounting for Asset Retirement Obligations," compared to the expense recovered for ratemaking purposes. The adjustments to investment income for these timing differences resulted in increases to the regulatory asset of $7.7 million and $1.3 million for the three-month period ended March 31, 2009 and 2008, respectively. Additionally, a $9.0 million decrease in the fair market value of the nuclear decommissioning fund contributed to the increase in the regulatory asset.

A new decommissioning site study will be performed later in 2009. The combination of the results from the decommissioning site study along with investment returns during 2009 will be utilized to assess whether additional decommissioning collections will be required in future years. Our management believes that any increase in the cost estimates of decommissioning or declines in investment earnings can be recovered in future rates. See Note 1 of Notes to Audited Consolidated Financial Statements for further discussion.

Additionally, a decrease in interest earnings on cash and cash equivalent instruments due to lower market interest rates on those investments in 2009 compared to 2008 contributed to the overall decrease in investment income.

Investment income decreased 29.4% in 2008 compared to 2007 and increased 4.6% in 2007 compared to 2006. The decrease in investment income for 2008 resulted primarily from realized investment losses sustained in the decommissioning trust fund. The income (loss) from investments in our external and internal decommissioning funds for 2008, 2007 and 2006 totaled ($32.2) million, $18.9 million and $22.5 million, respectively. As noted above, for nuclear decommissioning, we record a regulatory asset or liability for the timing difference in accretion expense recognized under SFAS No. 143, "Accounting for Asset Retirement Obligations," compared to the expense recovered for ratemaking purposes. The adjustments to investment income for these timing differences resulted in an increase to the regulatory asset of $48.5 million in 2008 and increases to the regulatory liability of $3.6 million and $5.1 million in 2007 and 2006, respectively. The increase to the regulatory asset in 2008 is primarily due to significant realized investment losses in the decommissioning trust fund.

In addition, a decrease of $13.2 million in earnings from cash and temporary cash investments as a result of lower average investment balances and lower interest rates on those investments contributed to the decrease in 2008 versus 2007.

Other interest increased in 2008 compared to 2007 primarily due to interest incurred on short-term borrowings. The increase in 2008 compared to 2007 in allowance for debt funds used during construction is primarily due an increase in construction work in progress for environmental compliance expenditures at coal-fired Plants Scherer and Wansley.

Our net margin for the three month-period ended March 31, 2009 was $15.6 million compared to $6.7 million for the same period of 2008, an increase of 133%. The primary reason for the increase in net margin for the three months ended March 31, 2009 compared to the same period in 2008 was due

to interest expense on long-term debt being lower than budgeted during the first quarter of 2009. In addition, higher budgeted net margin for 2009 also contributed to the increase in net margin for 2009 as compared to 2008.

Throughout the year, we monitor our financial results and, with the approval of our board of directors, make budget adjustments when and as necessary to ensure that a net margin equivalent to a 1.12 margins for interest ratio is achieved. Our management anticipates that the margin for the year ending December 31, 2009 will be approximately $26.9 million, which will yield a margins for interest ratio of 1.12. To enhance financial coverage during an anticipated period of generation facility construction, our board of directors approved a budget for 2009 to achieve a 1.12 margins for interest ratio (above the minimum 1.10 ratio required by the indenture). For additional information on our margin requirement, see "Summary of Cooperative Operations—Rates and Regulation." For additional information on our generation facility construction, see "OUR BUSINESS—Oglethorpe's Power Supply Resources—Future Power Resources."

Our net margin for 2008, 2007 and 2006 was $19.3 million, $19.1 million and $18.2 million, respectively. These amounts were exactly sufficient to meet the 1.10 margins for interest ratio requirement under the indenture. Our margin requirement is based on a ratio applied to interest charges. In addition, our margins include certain items that are excluded from the margins for interest ratio, such as non-cash capital credits allocation from Georgia Transmission. Our non-cash capital credits allocation from Georgia Transmission was $1.4 million, $1.4 million and $1.5 million for 2008, 2007 and 2006, respectively. (See "Summary of Cooperative Operations—Rates and Regulation.")

Our financial condition remains stable. In 2008, we achieved a margins for interest ratio of 1.10 as required by our indenture, which produced a net margin of $19.3 million. To enhance financial coverage during an anticipated period of generation facility construction, our board of directors approved a budget for 2009 projected to achieve a 1.12 margins for interest ratio. Net margin for the three months ended March 31, 2009 was $15.6 million, which increased our total patronage capital (equity) to $551 million. Our board of directors will evaluate coverage ratios throughout the period of anticipated construction and may choose to increase or decrease margins for interest coverage in the future.

We maintained a strong liquidity position with $964 million of unrestricted available liquidity at March 31, 2009. This $964 million of available liquidity does not include a $250 million credit commitment with the National Rural Utilities Cooperative Finance Corporation that we have the option to implement by December 31, 2009.

For the three-month period ended March 31, 2009, there was a net increase in long-term debt outstanding of approximately $380 million compared to December 31, 2008. The net increase was due to $350 million of first mortgage bonds issued in February 2009 and $59 million of funds advanced under approved Rural Utilities Service loans. The average interest rate on the $3.8 billion of long-term debt outstanding at March 31, 2009 was 5.5%.

Property additions for the three-month period ended March 31, 2009 totaled $82 million compared to property additions of $354 million for all of 2008. We are financing property additions with a combination of funds from operations and short-term and long-term borrowings. The expenditures were primarily for purchases of nuclear fuel, normal additions and replacements to existing generation facilities and environmental control facilities being installed at the coal-fired generating plants.

The three major rating agencies have all assigned investment grade credit ratings to us.

Sources of Capital. We have historically obtained the majority of our long-term financing from Rural Utilities Service-guaranteed loans funded by the Federal Financing Bank. However, Rural Utilities Service-guaranteed funding for new generation facilities is uncertain and may be limited at any point in the future due to budgetary and political pressures faced by Congress. Over the next ten years the loan demand of electric cooperatives is projected to exceed Rural Utilities Service-guaranteed funding authorization levels unless there is an increase over current levels of funding. In addition, there is currently a moratorium in place at the Rural Utilities Service regarding the funding of new baseload (coal and nuclear) generating facilities (see "OUR BUSINESS—Business Overview—Relationship with the Rural Utilities Service").

We have also obtained a substantial portion of our long-term financing requirements from the issuance of bonds in the taxable and tax-exempt capital markets, and expect to have a need to continue to access both of these markets in the future. The types of equipment that will qualify for tax-exempt financing, however, are fewer than in the past due to changes in tax laws and regulations.

Therefore, any generation facilities that we may build in the future will likely be financed long-term through a variety of sources, including Rural Utilities Service-guaranteed loans funded through the Federal Financing Bank, publicly or privately offered debt financings (both taxable and tax-exempt) and other financing sources.

In addition, our operations have historically provided a sizable contribution to the funding of capital requirements, such that internally generated funds have provided interim funding or long-term capital for nuclear fuel purchases, replacements and additions to existing generating facilities, general plant additions, and retirement of long-term debt. However, due to the significant amount of expenditures currently underway relating to environmental compliance projects and construction of new generation facilities, we are currently funding our capital requirements through a combination of funds generated from operations and short-term and long-term borrowings.

See "Capital Requirements—Capital Expenditures" for more detailed information regarding our estimated capital expenditures. See "Financing Activities" for more detailed information regarding our financing plans.

Liquidity. At March 31, 2009, we had $964 million of unrestricted available liquidity to meet short-term cash needs and liquidity requirements, consisting of $414 million of cash and cash equivalents and $550 million of unused and available committed short-term credit arrangements.

Net cash provided by operating activities was $121 million in 2008, and averaged $155 million for the three year period 2006 through 2008.

We have $550 million of committed credit arrangements comprised of three separate facilities as reflected in the table below:

At March 31, 2009, we had no commercial paper outstanding and no amounts were drawn under any of our credit facilities. Since March 31, we have issued $208 million of commercial paper related to the construction of the new Vogtle nuclear units and the acquisition of Heard County Power, L.L.C. and the related generation facility. For a discussion of Oglethorpe's plans regarding permanent financing of these generation facilities, see "Financing Activities."

We expect to renew these short-term credit facilities, as needed, prior to their respective expiration dates. All of the credit facilities provide for borrowings at either the bank's stated prime rate or the London Interbank Offered Rate (LIBOR), with LIBOR borrowings including a spread that is tied to our credit ratings.

Under the commercial paper program we are authorized to issue commercial paper in amounts that do not exceed the amount of any committed backup lines of credit, thereby providing 100% dedicated support for any paper outstanding. We periodically assesses our needs to determine the appropriate amount of commercial paper backup to maintain and currently have in place a $450 million committed backup credit facility provided by seven banks as shown in the table below:

The $450 million credit facility provides that if a participant bank is acquired, its successor is bound by the terms of the line of credit agreement. One of the participants, Wachovia Bank, N.A., was recently acquired by Wells Fargo Bank, N.A. Despite current market conditions, all the banks are performing their obligations under the credit facility.

The commercial paper backup line of credit contains a financial covenant requiring us to maintain minimum patronage capital of $400 million plus 75% of each year's positive net margin. As of March 31, 2009, the required minimum level was $429 million and our actual patronage capital was $551 million. An additional covenant under this facility limits our secured indebtedness to $8.5 billion and unsecured indebtedness to $4.0 billion. At March 31, 2009, we had approximately $3.8 billion secured indebtedness outstanding but had no unsecured indebtedness outstanding.

Along with the lines of credit from CoBank and Cooperative Finance Corporation, funds may be advanced under the backup line of credit supporting commercial paper for general working capital needs. In addition, under all three of these credit facilities we have the ability to issue letters of credit to third parties in amounts up to $50 million under each facility, or $150 million in the aggregate. However, any amounts related to issued letters of credit will reduce the amount available to draw as working capital under each facility. Also, due to the requirement to have 100% dedicated backup for any commercial paper outstanding, any amounts drawn under the commercial paper backup line for working capital or related to issued letters of credit will reduce the amount of commercial paper that we can issue.

In January 2009, we signed a commitment letter with Cooperative Finance Corporation for up to $166 million in credit and in May we signed an amended committment letter increasing the credit committment to $250 million, to be extended in the form of any one, or any combination, of the following three options: (i) as a five year secured "stand alone" revolving construction facility, (ii) as a

secured backstop to a syndicated revolving construction facility or (iii) as a secured long-term asset loan (up to 35 years). The pricing for each option is subject to Cooperative Finance Corporation's current pricing for member borrowers at the time we elect to implement one or more of the credit options. This multi-option credit commitment extends through December 31, 2009, and we anticipate implementing the revolving construction facility option sometime in the summer of 2009.

We are continuing to pursue additional credit facilities that would further enhance our liquidity throughout the anticipated period of generation facility construction. The timing, size and term of potential additional facilities will be influenced by many factors, including the ultimate size of the construction program and market conditions. Between projected cash on hand and the credit facilities currently in place or under option, we believe we will have sufficient liquidity to fund our construction program and to cover normal operations through 2010.

In December 2008, we instituted a power bill prepayment program pursuant to which members can prepay their power bills from us at a discount for an agreed number of months in advance, after which point the funds are credited against the participating members' monthly power bills. Since the program began, fourteen members have prepaid $191 million which will be applied against their bills beginning in May 2009 and extending through June 2011. This program is providing us with additional liquidity prior to the point the funds are credited against monthly power bills.

In addition to unrestricted available liquidity, we had $80 million in restricted short-term investments at March 31, 2009 pursuant to deposits made into a Rural Utilities Service Cushion of Credit Account. The deposits with the U.S. Treasury were made voluntarily and earn a guaranteed rate of interest of 5% per annum. The funds in the account, including interest thereon, can only be applied to debt service on Rural Utilities Service notes and Rural Utilities Service-guaranteed Federal Financing Bank notes. We may choose to apply these funds toward debt service payments later in 2009.

Liquidity Covenants. At March 31, 2009, we had only one financial agreement in place containing a liquidity covenant. This covenant is in connection with the Rocky Mountain lease transactions and requires us to maintain minimum liquidity of $50 million at all times during the term of the lease. We had sufficient liquidity to meet this covenant in 2008 and expect to have sufficient liquidity to meet this covenant in 2009.

Beginning in late 2007 and throughout 2008, the three major credit rating agencies downgraded the debt of substantially all of the historically triple-A rated monoline bond insurers as a result of their exposure to financial guarantees provided on structured finance obligations backed by subprime residential mortgages. All four of the monoline insurers providing insurance on our variable rate pollution control bond debt at the beginning of 2008 have lost one or more of their triple-A ratings.

Bond insurer downgrades have affected the credit spreads of both variable rate demand bonds and auction rate securities. Variable rate demand bonds are bonds that are subject to periodic optional tenders by bondholders. A remarketing agent periodically resets the interest rate on the bonds at a rate that allows it to remarket tendered bonds to new holders at par. If the variable rate demand bonds were tendered by bondholders and the remarketing agent was unable to sell the bonds to new holders, we had in place standby bond purchase agreements with banks that obligated the banks to purchase the bonds that could not be remarketed. Our variable rate demand bonds were backed by bond insurance and, as a result of the bond insurer downgrades, the remarketing agents were either unable to remarket our variable rate demand bonds, or were only able to do so at much higher interest rates. The variable rate demand bonds that could not be remarketed were purchased by the banks pursuant to the standby bond purchase agreements and bore interest at significantly higher rates.

Auction rate securities re-price in Dutch auctions that occur every 7 to 35 days, and historically investors could seek to liquidate these securities at the end of any auction period. But in 2008, as bond insurers began to be downgraded, investors shunned the auction rate securities market, leading to increased focus on the underlying issuer credit, wider credit spreads, and eventually failed auctions. The auction rate securities market is currently not a functioning market and many auctions are now failed auctions.

At the beginning of 2008, we had outstanding $410 million of pollution control bonds in the variable rate demand mode and $434 million of pollution control bonds in the auction rate securities mode. During most of 2008, the periodic auctions on our issued auction rate securities failed for the reasons described above, with the result that the investors, or in some cases our broker dealers, continue to hold the bonds. Pursuant to our auction rate securities related bond documents, some of our failed auction rates set at maximum rates of 12% while others set at 125% to 225% of LIBOR, as determined by the rating on the bonds. We also had a substantial amount of our variable rate demand bonds purchased by banks pursuant to the standby bond purchase agreements due to the remarketing agents' inability to remarket the bonds, again as a result of bond insurer downgrades. These events resulted in higher variable rates of interest on the bonds, in some instances as high as 12%. See "Financing Activities" for a discussion of the transactions we completed in 2008 to address the issues caused by bond insurer downgrades.

We had $47 million of our general funds invested in auction rate securities of other companies at the beginning of 2008, and early in the year undertook an effort to liquidate those investments. However, due to failed auctions we were able to liquidate only a small amount of our holdings during the year. At December 31, 2008 and March 31, 2009, the par value of our investments in auction rate securities totaled approximately $31 million, net of a $7 million other-than-temporary impairment recorded at year-end. These securities have maturities in excess of one year and as such are classified as long-term investments. We continue to try to liquidate these investments when and as possible.

Because there was insufficient observable market information available to determine the fair value of our temporarily impaired auction rate securities investments, we estimated the fair value of these investments using a discounted cash flow model. The assumptions used in preparing the discounted cash flow model included estimates (based on data available at each quarter end) of projected cash flows at current rates adjusted for illiquidity premiums (which were based on discussions with market participants). The result was a reduction in the par value of these investments (related to temporary impairments) of $1.7 million as of December 31, 2008 and a further reduction in the par value of these investments of $24,000 as of March 31, 2009. The various assumptions we utilize to determine the fair value of our auction rate securities investments will vary from period to period based on prevailing economic conditions. For example, if the market for our auction rate securities investments continues to deteriorate, we may need to increase the illiquidity premium used in preparing a discounted cash flow model for these securities. Such an increase may result in a further decrease in the fair value of these securities. A hypothetical 25 basis point increase in the illiquidity premium used to determine the fair value of our auction rate securities investments would have decreased the fair value of these investments by approximately $2 million at December 31, 2008 and at March 31, 2009.

To facilitate our financing plans, especially in light of the significant amount of financing required for the new generation construction, we amended the indenture in February 2009, with the consent of a majority of the holders of indenture obligations outstanding, to (i) allow us to finance construction of generation and related facilities by issuing indenture obligations based on a percent of progress payments made under contracts for engineering, construction or procurement services that have been pledged under the indenture, and (ii) remove the restriction on short-term indebtedness (i.e. short-term indebtedness cannot exceed 15% of total capitalization) from the indenture. In connection with

providing its consent to the indenture changes, the Rural Utilities Service required an amendment to our Amended and Restated Loan Contract with the Rural Utilities Service pursuant to which a less restrictive short-term indebtedness provision was incorporated. The new covenant provides that until December 31, 2014, our short-term indebtedness shall not exceed 30% of total utility plant, and thereafter it shall not exceed 15% of total capitalization unless the Rural Utilities Service has granted an extension of the higher amount.

Rural Utilities Service-Guaranteed Loans. We currently have three approved Rural Utilities Service- guaranteed loans totaling $612 million. The approved loans are for the purpose of funding: (i) approximately $185 million of normal additions and replacements at existing generation facilities through 2011 and (ii) approximately $427 million of expenditures through 2014 relating to compliance with environmental regulations. All three of the approved Rural Utilities Service loans have closed, and to date, $183 million has been advanced under the loans, leaving $429 million to be advanced. We do not expect to have all three loans fully drawn until 2014.

In addition, in September 2008 we submitted four applications for Rural Utilities Service-guaranteed loans totaling $1.3 billion that are still pending. If approved, these loans will fund: (i) a $459 million 100 megawatt biomass facility estimated to be in-service by 2014, (ii) a $474 million 100 megawatt biomass facility estimated to be in-service by 2015, (iii) $121 million in general improvements at existing generation facilities and (iv) $210 million of environmental projects at coal-fired Plants Scherer and Wansley. We do not expect the two loans for the biomass facilities to be approved before 2011; however, we anticipate a decision on the other two loans in 2009.

In 2009, we anticipate submitting a loan application to the Rural Utilities Service in connection with our acquisition of Heard County Power, L.L.C., which owns a generating facility consisting of three combustion turbines with an aggregate capacity of approximately 500 megawatts. To the extent members subscribe to our construction of gas-fired combustion turbine plants and combined cycle plants, we anticipate filing Rural Utilities Service loan applications for these facilities as well (see "OUR BUSINESS—OGLETHORPE'S POWER SUPPLY RESOURCES—Future Power Resources").

All of the approved Rural Utilities Service loans will be funded through the Federal Financing Bank and guaranteed by the Rural Utilities Service, and the debt will be secured under the indenture.

Department of Energy-Guaranteed Loans. In connection with our participation in two new nuclear units at the existing Plant Vogtle site, in September 2008 and December 2008, we submitted Part I and Part II loan applications, respectively, in connection with the Department of Energy loan guarantee program seeking funding for the project. Two of the other three co-owners in the new Vogtle units have also applied for funding under the loan guarantee program. We are pursuing this funding source as a result of a moratorium currently in place at the Rural Utilities Service regarding the funding of new baseload (coal and nuclear) generating plants. The Department of Energy loan guarantee program, which is intended to support commercialization of innovative technologies to reduce air pollutants including greenhouse gases, was initially authorized pursuant to the Energy Policy Act of 2005 and was subsequently funded and extended. The loan structure would entail a loan funded through the Federal Financing Bank carrying a federal loan guarantee provided by the Department of Energy. The Department of Energy recently notified us that the Vogtle project has been selected for final due diligence and detailed negotiations leading to a potential conditional commitment for a Department of Energy federal loan guarantee. The term sheet negotiation phase is anticipated to extend into the fourth quarter of 2009, and a final decision on loan approval is not anticipated until late in 2009. Even if funding is obtained, the Department of Energy only has authority to fund up to 80% of the full cost of the project. Therefore we will seek other sources of funding, including the issuance of taxable bonds and tax-exempt bonds for any equipment that may qualify for such tax-exempt funding for the portion of the project not financed through the loan guarantee program.

See "OUR BUSINESS—Our Power Supply Resources—Future Power Resources" for a discussion of our participation in new generation facilities. See "OUR BUSINESS—Relationship with the Rural Utilities Service" for a discussion of the Rural Utilities Service's current position relating to funding of new generation facilities.

Bond Financings. We have received tax-exempt financing allocations from the State of Georgia totaling $200 million. In 2006, we received $150 million of allocations related to equipment being installed at Plant Scherer to control mercury emissions. In 2008, we received $50 million of allocations related to scrubbers being installed at Plant Wansley to reduce sulfur dioxide emissions. It is uncertain at this time if enough of this equipment will qualify to take advantage of the full amount of the allocations. The tax-exempt bonds can be issued any time within a three-year window that begins the year after the allocation was awarded. Currently, we anticipate issuing tax-exempt bonds for both projects in late 2009 or 2010. We also plan to seek additional state allocation in 2009 for tax-exempt financing related to a scrubber installation project currently underway at Plant Scherer.

In 2006, we received an allocation from the Internal Revenue Service, or IRS, to issue $24 million of clean renewable energy bonds to fund an upgrade project currently underway at our Rocky Mountain generating facility. Clean renewable energy bonds are zero coupon bonds, and in lieu of receiving an interest payment from the issuer the bondholder receives a credit against federal income tax liability. We had our clean renewable energy bond application submitted to the IRS on our behalf by Cooperative Finance Corporation, along with the applications of other electric cooperatives. Cooperative Finance Corporation, as a qualified issuer under the program, will issue the bonds and in turn loan the proceeds at a low rate of interest (approximately 1%) to the cooperatives whose applications were approved. We anticipate a closing on our $24 million CREBs related loan with Cooperative Finance Corporation later in 2009.

We have a program in place under which we are refinancing, on a continued tax-exempt basis, the annual principal maturities of pollution control bonds originally issued on our behalf by various county development authorities. The refinancing of these pollution control bonds' principal maturities allows us to preserve a low-cost source of financing. To date, we have refinanced approximately $270 million under this program, including $10 million of principal that matured in January 2009 (of which Georgia Transmission had an assumed obligation to pay $1.7 million, as discussed below). We have board approval to continue this refinancing program covering an additional $35 million of pollution control bonds principal maturing through 2012.

Under an indemnity agreement executed in connection with Georgia Transmission's assumption of pollution control bond indebtedness as part of our 1997 corporate restructuring (see "Off-Balance Sheet Arrangements—Georgia Transmission Debt Assumption"), and additional indemnity agreements executed in connection with Georgia Transmission's assumption of pollution control bond refunding indebtedness in 2006, 2007 and 2008, Georgia Transmission is entitled to participate in any future prepayment of its assumed pollution control bond debt by agreeing to assume a portion of the refunding indebtedness. As such, Georgia Transmission elected to participate in our refinancing of the January 2009 maturity, and we anticipate that Georgia Transmission will continue to participate in the refinancing of the $35 million of pollution control bond principal maturing through 2012 as discussed above.

In connection with the extension of our wholesale power contracts from 2025 to 2050, we embarked on a program in 2006 to refinance or otherwise reamortize a portion of our pollution control bond and Federal Financing Bank debt. An extension of the debt maturities provides for better alignment of principal amortization with the projected useful lives of our assets, which are currently projected to operate well beyond the original contract termination date of 2025. To date, we have extended the maturities on approximately $1.7 billion of our Federal Financing Bank and pollution control bond indebtedness. Included in this amount were two separate transactions that closed in 2008 covering $265 million of pollution control bond debt.

In light of the bond insurer downgrades and related events described under "Negative Events in the Capital Markets," we refinanced or otherwise converted the interest rate modes on a significant portion of our variable rate pollution control bond indebtedness in 2008 as discussed below.

In a remarketing that closed in April 2008, we converted $134 million of Series 2006 pollution control revenue bonds and $182 million of Series 2007 pollution control revenue bonds, both of which were in the auction rate securities mode, to a term rate mode using 2 and 3-year put bonds as we had the option to do pursuant to the underlying bond documents. The interest mode conversions were undertaken due to downgrades of the bond insurers. We still have $123 million of auction rate securities that remain outstanding, but any decision to refinance those bonds will depend on future market conditions, including the interest rate environment.

In a transaction that closed in August 2008, we refinanced $255 million of pollution control revenue bonds that were previously in a weekly variable rate demand mode through the issuance of $255 million of Series 2008 fixed rate refunding bonds. While this transaction was undertaken mainly to replace a downgraded bond insurer, this transaction also provided for an immediate extension of the maturities, rather than over time as the principal on the refunded pollution control bond debt was set to mature each year.

In a transaction that closed in December 2008, we refinanced another $248 million of pollution control revenue bonds, including $238 million of Series 2006 bonds that were previously in a commercial paper variable rate demand mode and $10 million of annual principal that was set to mature in January 2009. The $238 million of Series 2006 pollution control revenue bonds had already had their maturities extended but were refinanced due to a downgrade of the bond insurer, while the $10 million of annual principal was refinanced for the purpose of extending the maturities. We issued $103 million of the Series 2008 refunding bonds in a term rate mode and the remaining $145 million of Series 2008 refunding bonds were issued with rates fixed to maturity. Georgia Transmission had previously assumed $40 million of the Series 2006 bonds that were refunded and Georgia Transmission also assumed $40 million of the Series 2008 refunding bonds.

In February 2009, we issued $350 million of Series 2009 fixed rate first mortgage bonds. The bonds were issued for the purpose of financing a portion of the cost of construction of new generation facilities, to enhance existing generation facilities and to provide liquidity for general corporate purposes.

In the second half of 2009 we anticipate issuing additional first mortgage bonds of up to $500 million to fund construction of new generation facilities and to provide liquidity for general corporate purposes.

All of the pollution control revenue bonds and first mortgage bonds issued in 2008 and early 2009 were secured under the indenture.

Capital Expenditures. As part of our ongoing capital planning, we forecast expenditures required for generating facilities and other capital projects. The table below details these expenditure forecasts for 2009 through 2011. Actual expenditures may vary from the estimates listed in the table because of factors such as changes in business conditions, design changes and rework required by regulatory bodies, delays in obtaining necessary regulatory approvals, construction delays, changing environmental requirements, and changes in cost of capital, equipment, material and labor.

We expect to spend an additional $3.7 billion above the amounts reflected in the table above to complete construction of the two Plant Vogtle nuclear units and the two biomass facilities by 2017. For information about steps we have taken to procure financing for these projects, see "Financing Activities."

In addition to the new nuclear units and the biomass facilities, we have identified other electric generation options that we could pursue to meet our members' future energy needs (see "OUR BUSINESS—Our Power Supply Resources—Future Power Resources"), including the possible construction of new combined cycle and combustion turbine facilities that are not included in the capital expenditure table above. The projects that we may ultimately construct, if any, as well as the cost of construction, are not known at this time.

We have also acquired, from a subsidiary of Dynegy Inc., Heard County Power, L.L.C., which owns a 500 megawatt peaking facility in Heard County, Georgia, and assumed an existing off-take contract, for $105 million, which is not included in the table above.

We are 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 (particularly in relation to climate change), it is difficult to predict what capital costs may ultimately be required. The environmental compliance expenditures reflected in the table above include the installation of (i) a flue gas desulfurization project at Plant Wansley, one unit of which was placed in service at the end of 2008 and the second unit of which is scheduled to be placed in service in the second quarter of 2009 and (ii) at Plant Scherer, a mercury removal project, a flue gas desulfurization project and a selective catalytic reduction system project all currently underway and all expected to be

in service by 2014. To complete the Plant Scherer projects, we expect to spend an additional approximately $300 million beyond what is reflected in the table above.

Depending on how we and the other co-owners of Plants Wansley and Scherer choose to comply with any future regulations, both capital expenditures and operating expenditures may be impacted. As required by the wholesale power contracts, we expect to be able to recover from our members all capital and operating expenditures made in complying with current and future environmental regulations. For additional information, see "OUR BUSINESS—Environmental And Other Regulation."

As with utilities generally, inflation has the effect of increasing the cost of our 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. While we cannot predict what level of inflation may occur in the future, in light of current U.S. financial policies the potential for inflationary pressures exist.

The table below reflects, as of December 31, 2008, our contractual obligations for the periods indicated.

We have financial and other contractual agreements in place containing provisions which, upon a credit rating downgrade below specified levels, may require the posting of collateral in the form of letters of credit or other acceptable collateral. Our primary exposure to potential collateral postings is at rating levels of BBB-/Baa3 or below. As of March 31, 2009, our maximum potential collateral requirements were as follows:

Provisions in the Rural Utilities Service Loan Contract and certain pollution control bond agreements contain covenants based on credit ratings that, upon a credit rating downgrade below specified levels, could result in increased interest rates or restrictions on issuing debt. Also, borrowing rates and commitment fees in the existing Cooperative Finance Corporation, CoBank and commercial paper line of credit agreements are based on credit ratings and could increase if our ratings are lowered. None of these covenants, however, would result in acceleration of any debt due to credit rating downgrades.

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

We are liable for certain contractual obligations for which other parties are liable, and we would be expected to pay only if the other parties fail to satisfy such obligations. These obligations are not shown on our balance sheet and are described below.

Georgia Transmission Debt Assumption. In connection with our corporate restructuring in 1997 in which we sold our transmission related assets to Georgia Transmission (which represented 16.86% of our assets), Georgia Transmission assumed 16.86% of the then outstanding indebtedness associated with pollution control bonds pursuant to an assumption agreement and an indemnity agreement. If Georgia Transmission fails to satisfy its obligations under this debt assumption, we remain liable for any unsatisfied amounts. In that event, we would be entitled to reimbursement from Georgia Transmission for any amounts we paid. At March 31, 2009, the total obligation assumed by Georgia Transmission relating to outstanding pollution control bond principal was $94 million. Georgia Transmission's

estimated payments of principal and interest in 2009 pursuant to this assumed obligation are approximately $7 million.

Rocky Mountain Lease Arrangements. In December 1996 and January 1997, we entered into six long-term lease transactions relating to our 74.61% undivided interest in Rocky Mountain. In each transaction, we leased a portion of our undivided interest in Rocky Mountain to an owner trust for the benefit of an investor (referred to as an owner participant) 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. There are three separate investors (owner participants) in the Rocky Mountain lease transactions. Each owner participant/owner trust funded a portion of its payment to us 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 our wholly owned subsidiary, Rocky Mountain Leasing Corporation (RMLC), for a term of 30 years under separate leases, referred to as the facility leases. RMLC then subleased the undivided interests back to us for an identical term also under separate leases, referred to as the facility subleases.

We used a portion of the one-time rental payments paid to us 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 six payment undertaking agreements (in the aggregate totaling $641 million) with Rabobank Nederland and six equity funding agreements (in the aggregate totaling $57 million) with AIG Matched Funding Corp. that provide for these third parties to pay all of:

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

The facility subleases require us 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 2008, the amount of the rental payments under the facility subleases and facility leases each totaled $54 million. The payment undertaking agreements require the payment undertaker (Rabobank) to pay the rent payments directly to the owner trust's lender in satisfaction of RMLC's rent payment obligation under the facility leases and the applicable owner trust's repayment obligation under the loans used to finance a portion of the one-time rental payments to us described above. Because RMLC funds these rent payments through the payment undertaking agreements, RMLC returns to us, in the form of a patronage dividend, amounts received by it pursuant to the facility subleases other than amounts RMLC requires to fund its expenses. RMLC remains liable for all rental payments under the facility leases (and would not be able to make such patronage dividend to us) 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 us.

The senior unsecured debt obligations of Rabobank are rated AAA by S&P and Aaa by Moody's. RMLC has the right to replace Rabobank as the payment undertaker with substitute credit protection of certain approved governmental or other entities, including banks or financial institutions rated at least AA by S&P and Aa2 by Moody's; provided that any replacement therefore is subject to approval by the owner participants in accordance with their internal credit policies and guidelines. If, as a result of replacing the payment undertaker, the lender requests a higher interest rate on the loans, RMLC

will be required to find a replacement lender to purchase the loan certificates from the lender unless the owner participants consent to such increase in the interest rate.

AIG Matched Funding Corp. is a wholly owned subsidiary of AIG, and AIG has guaranteed the obligations of AIG Matched Funding Corp. under the equity funding agreements. At the time the lease transactions were entered into, AIG's senior unsecured debt obligations were rated AAA by S&P and Aaa by Moody's. The equity funding agreements provide that if AIG fails to maintain a credit rating of at least AA- from S&P and Aa3 from Moody's, then AIG Matched Funding Corp. will be required to post collateral having a stipulated credit quality to secure its obligations thereunder.

In September 2008, S&P lowered AIG's rating to A- and Moody's lowered AIG's rating to A2, putting the ratings below the collateralization threshold. As a result of the downgrades, AIG Matched Funding Corp. posted collateral in compliance with the equity funding agreements, consisting of securities issued by an instrumentality of the United States government that are rated AAA in an amount equal to 105% of the net present value of its future payment obligations related to the equity portion of the fixed purchase price. In accordance with the terms of the equity funding agreements, the market value of the posted collateral (other than cash) is determined weekly by an independent third party and AIG Matched Funding Corp. is required to post additional collateral to the extent that it is determined that the market value of such collateral, together with the cash collateral (if any), has fallen below an amount equal to 105% of the net present value of its future payment obligations related to the equity portion of the fixed purchase price. According to U.S. Bank National Association, which as collateral agent holds the collateral and provides the weekly valuation thereof, the market value of the collateral was $115 million at March 31, 2009. Moody's further lowered AIG's rating to A3 in October 2008.

If AIG fails to comply with its collateralization obligations or fails to maintain a credit rating of at least BBB- from S&P and Baa3 from Moody's, then RMLC must, within 60 days of becoming aware of such fact, enter into replacement equity funding agreements with a financial institution that has credit ratings of at least AA- from S&P and Aa3 from Moody's. If such replacement is triggered by AIG's failure to provide sufficient collateral, RMLC would have the right to terminate the equity funding agreements at the higher of market value or accreted value (as determined in each case). However, if AIG is rated below BBB- from S&P and below Baa3 from Moody's, but AIG Matched Funding Corp. is in compliance with its collateralization requirement, RMLC would not have a right to terminate the equity funding agreements in connection with a replacement. In the event that RMLC is not able to enter into replacement equity funding agreements, then RMLC may be required to purchase the owner trusts' equity interests from the owner participants.

The operative agreements relating to the Rocky Mountain lease transactions also require us to maintain surety bonds with a surety bond provider that meets minimum credit rating requirements to secure certain of our payment obligations under the Rocky Mountain lease transactions. Accordingly, we entered into a surety bond arrangement with AMBAC concurrently with the consummation of the Rocky Mountain lease transactions.

The operative agreements relating to the Rocky Mountain lease transactions provide that if the surety bond provider fails to maintain a credit rating of at least AA from S&P or Aa2 from Moody's, then we must, within 60 days of becoming aware of such fact, provide (i) a replacement surety bond from a surety bond provider that has such credit ratings, (ii) a letter of credit from a bank with such credit ratings, (iii) other acceptable credit enhancement or (iv) any combination thereof. In the event that we are unable to obtain replacement credit enhancement, then we may be required to purchase the owner trusts' equity interests from the owner participants.

On November 19, 2008, S&P lowered AMBAC's credit rating from AA to A. Because AMBAC already had a credit rating of Baa1 from Moody's, such action by S&P triggered the requirement for us

to provide the replacement credit enhancement discussed above. Each of the three owner participants granted us extensions of time to provide this replacement credit enhancement.

On May 22, 2009, we entered into an agreement with Berkshire Hathaway Assurance Corporation (Berkshire) and two of the three owner participants, pursuant to which Berkshire (rated AAA by S&P and Aa1 by Moody's) will provide supplemental credit enhancement to the credit enhancement currently provided by AMBAC with respect to five of the six long-term lease transactions. As a result, our obligation to provide replacement credit enhancement with respect to these five long-term lease transactions has been satisfied.

In addition, we expect to enter into an agreement with Berkshire and the third owner participant for Berkshire to replace AMBAC as the credit enhancement provider with respect to the sixth long-term lease transaction. However, in the event we are unable to implement this replacement credit enhancement within any additional time extensions granted by this owner participant, then we may be required to purchase the equity interest of this owner participant in the owner trust. We currently estimate that the maximum aggregate amount of exposure we would have if we were required to purchase this equity interest is approximately $25 million. This amount is net of the accreted value of the guaranteed investment contracts that were entered into with AIG Matched Funding Corp. in connection with the six long-term lease transactions. The actual value of the guaranteed investment contracts may be more or less than the accreted value as a result of changes in interest rates and market conditions. We expect to have adequate liquidity to purchase the equity interest based on the maximum aggregate amount of exposure of approximately $25 million if we were required to do so.

In the future, we may be required to purchase the equity interests of one or more of the owner participants in the owner trusts under the circumstances described above. We estimate that the current maximum aggregate amount of exposure we would have if we were required to purchase the equity interests of all six owner trusts is approximately $250 million, and this amount will begin to decline in 2011 until it reaches zero by the end of the lease term in 2027. This amount is net of the accreted value of the guaranteed investment contracts that were entered into with AIG Matched Funding Corp. in connection with the Rocky Mountain lease arrangements, which are discussed in detail above.

As our wholly owned subsidiary, the financial condition and results of operations of RMLC are fully consolidated into our financial statements. The equity funding agreements and corresponding lease obligations are reflected on our balance sheets as Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions ($110 million at March 31, 2009 and $108 million at December 31, 2008). However, our financial statements 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 our balance sheets at December 31, 2008 and March 31, 2009, both the Deposit on Rocky Mountain transactions and Obligation under Rocky Mountain transactions would have been higher by $711 million and $700 million, respectively. However, it would have no effect on our statements of operations or cash flows.

The assets of RMLC, including the payment undertaking agreements and the equity funding agreements, are not available to pay our creditors or our affiliates' creditors.

At the end of the term of each facility lease, we have 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 equity 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 we do not elect to cause RMLC to purchase any owner trust's undivided interest in Rocky Mountain, Georgia Power has an option to

purchase that undivided interest. If neither we nor Georgia Power exercise our purchase option, and we return (through RMLC) any undivided interest in Rocky Mountain to an owner trust, that owner trust has several options it can elect, including:

Under the first two of these options we must arrange new financing for the outstanding amount of the loans used to finance the owner trusts' one-time rental payments, described above. 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 us to purchase 49%, in the case of the first option above, or all, in the case of the second option above, of the loan certificates or cause RMLC to exercise its purchase option or RMLC and us to renew the facility leases and facility subleases, respectively.

If option one above is chosen, at the end of the 16-year lease renewal 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.

Due to our cost-based rate structure, we have limited exposure to market risks. However, changes in interest rates, equity prices, and commodity prices may result in fluctuations in member rates. We use derivatives only to manage this volatility and do not use derivatives for speculative purposes. (See "OUR BUSINESS—Business Overview—Electric Rates" for further discussion of our rate structure.)

We have a risk management committee that provides general oversight over all risk management activities, including commodity trading, fuels management, insurance procurement, debt management and investment portfolio management. This committee is comprised of our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and the Executive Vice President, Member and External Relations. The risk management committee has implemented comprehensive risk management policies to manage and monitor credit and market price risks. These policies also specify controls and authorization levels related to various risk management activities. The committee frequently meets to review corporate exposures, risk management strategies, and hedge positions. The risk management committee regularly reports corporate exposures and risk management activities to the audit committee of our board of directors.

We are exposed to the risk of changes in interest rates related to our $464 million of variable rate debt, the vast majority of which relates to $123 million of pollution control bond debt (in auction rate mode) that is subject to repricing every 35 days and $337 million of term rate debt (mostly pollution control bond debt) that is subject to repricing from March 2010 through April 2012. At March 31, 2009, the weighted average interest rate on this variable rate debt was 3.9%. If interest rates on this debt changed a hypothetical 100 basis points on the respective repricing dates and remained at that level for the remainder of the year, annual interest expense would change by approximately $1.2 million in 2009.

Our objective in managing interest rate risk is to maintain a balance of fixed and variable rate debt that will lower our overall borrowing costs within reasonable risk parameters. As part of this debt management strategy we have general guideline of having between 15% and 30% variable rate debt to total debt (including capital lease debt). At March 31, 2009, we had 12.0% of our debt in a variable rate mode. The amount of variable rate debt outstanding declined in 2008 due to refinancings of pollution control bond debt related to bond insurer downgrades, where a portion of the refunding debt was issued in a fixed rate mode versus the prior variable rate mode. Based on current market conditions and our future capital needs, we believe our variable rate debt as a percent of total debt will likely remain at levels below the general guidelines for the foreseeable future.

The operative documents underlying the pollution control bond debt contain provisions that allow us to convert the debt to a variety of variable interest rate modes (such as daily, weekly, monthly, commercial paper, auction rate or term rate mode), or to convert the debt to a fixed rate of interest to maturity. Having these interest rate conversion options improves our ability to manage our exposure to variable interest rates.

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

In December 1985, we sold and subsequently leased back from four purchasers our 60% undivided ownership interest in Scherer Unit No. 2. The capital leases provide that our 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 $47 million in serial facility bonds due June 30, 2011 with a 6.97% fixed rate of interest.

We 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 our 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 March 31, 2009, the weighted average interest rate on the lease obligation was 6.0%.

We maintain external trust funds (reflected as "Decommissioning fund" on the balance sheet) to fund our share of certain costs associated with the decommissioning of our nuclear plants as required by the Nuclear Regulatory Commission (see Note 1 of Notes to Audited Consolidated Financial Statements). We also maintain an internal reserve for decommissioning (included in "Long-term investments" on the balance sheet) from which funds can be transferred to the external trust fund, if necessary.

The allocation of equity and fixed income securities in both the external and internal funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in decommissioning costs; however, the equity portion of these funds is exposed to price fluctuations in equity markets, and the values of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the funds and periodically review asset allocation in accordance with our nuclear decommissioning fund investment policy. Our investment policy establishes targeted and permissible investment allocation ranges for equity and fixed income securities. The targeted asset allocation is diversified among various asset classes and investment styles. Specific investment guidelines are established with each of the investment advisors that are selected to manage a particular asset class or subclass.

The investment guidelines for equity securities typically limit the type of securities that may be purchased and the concentration of equity holdings in any one issuer and within any one sector. With respect to fixed-income securities, the investment guidelines set forth limits for the type of bonds that may be purchased, state that investments be primarily in securities with an assigned investment grade rating of BBB- or above and establish that the average credit quality of the portfolio typically be A+/A1 or higher.

Our nuclear decommissioning funds (external and internal combined) declined approximately 18% in value in 2008 and declined further by 5% in the first quarter of 2009. We will perform an analysis of funding adequacy in 2009 and potential changes, if any, in funding requirements will be evaluated at that time.

A 10% decline in the value of the fund's equity securities as of March 31, 2009 would result in a loss of value to the fund of approximately $11 million. For further discussion on our nuclear decommissioning trust fund, see Note 1j of Notes to Audited Consolidated Financial Statements.

We are also exposed to the risk of changing prices for fuels, including coal and natural gas. We have interests in 1,501 megawatts of coal-fired capacity, Plants Scherer and Wansley. We purchase coal under term contracts and in spot-market transactions. Some of our coal contracts provide volume flexibility and most have fixed or capped prices. We anticipate that our existing contracts will provide fixed prices for nearly 100% of our forecasted coal requirements in 2009 and fixed or capped prices for over 65% of our forecasted coal requirements in 2010.

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

We own three gas-fired generation facilities, either directly or through a wholly owned subsidiary, totaling 1,586 megawatts of capacity. (See "OUR BUSINESS—Properties—Generating Facilities.")

We also have power purchase contracts with Doyle I, LLC (treated as a capital lease) and Hartwell under which approximately 625 megawatts of capacity and associated energy is supplied by gas-fired facilities. (See "OUR BUSINESS—Our Power Supply Resources—Power Purchase and Sale Arrangements—Power Purchases" and "OUR BUSINESS—Properties—Generating Facilities.") Under these contracts, we are exposed to variable energy charges, which incorporate each facility's actual operation and maintenance and fuel costs. We have the right to purchase natural gas for Doyle and the Hartwell facility and exercise this right 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, we purchase natural gas, including transportation and other related services, on behalf of Smarr EMC and ensure that the Smarr facilities have fuel available for operations. (See "OUR BUSINESS—Our Members and Their Power Supply Resources—Member Power Supply Resources" and "OUR BUSINESS—Properties—Generating Facilities" and "—Fuel Supply.")

We enter into natural gas swap arrangements to manage our exposure to fluctuations in the market price of natural gas. Under these swap agreements, we pay the counterparty a fixed price for specified natural gas quantities and receive 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, we will make a net payment, and if the market price index is higher than the fixed price, we will receive a net payment. If the natural gas swaps had been terminated on March 31, 2009, we would have made a net payment of approximately $35.4 million. We have obtained our 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. We are providing natural gas price risk management services to 15 of our 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.

Our exposure to changes in interest rates, the price of equity securities we hold, and commodity prices have not changed materially from our previous reporting period. We are not aware of any facts or circumstances that would significantly impact these exposures in the near future; however, nonperformance by one of our hedge counterparties may increase our exposure to market volatility.

On May 1, 2008, our members adopted amendments to our bylaws providing for restructuring of the composition of our board of directors. Pursuant to these amendments, our board of directors will continue to be comprised of directors elected from our members, referred to as "member directors," and up to two independent outside directors. The previous bylaws divided member director positions among five geographical regions of the State of Georgia, providing for member director positions for a general manager of a member located in each region and a director of a member located in each region.

Rather than dividing member director positions among five geographical regions, the bylaw amendments divide member director positions among five member scheduling groups specifically described in the bylaw amendments, and referred to as the "member groups." Similar to the previous bylaws, member director positions are provided for a general manager of a member in each member group and a director of a member in each member group. The bylaw amendments permit expansion of the number of member groups and changes in the composition of member groups. Formation of new member groups and changes in the composition of member groups are subject to certain required member approvals, and the requirement that the composition of the member groups at Oglethorpe, Georgia Transmission and Georgia System Operations be identical, except in cases where a member is no longer a member of one or more of Oglethorpe, Georgia Transmission or Georgia System Operations. The number of member director positions will change if additional member groups are formed or a member group ceases to exist. The bylaw amendments also expand the number of at-large member director positions from one to three and provide for these to be filled by a director of a member.

In an effort to provide for equitable representation among the member groups across the boards of directors of Oglethorpe, Georgia Transmission and Georgia System Operations, the bylaw amendments provide for certain limitations on the eligibility of directors of members of each member group to fill the three at-large member director positions. No more than one at-large member director position on our board of directors may be filled by a director of a member of any member group, no more than two directors from members of any member group may be serving in at-large member director positions on the boards of directors of Oglethorpe, Georgia Transmission and Georgia System Operations, and at least one at-large member director position on the boards of directors of Oglethorpe, Georgia Transmission or Georgia System Operations must be filled by a director of a member of each member group that has at least two members. As under the previous bylaws, a member may not have both its general manager and one of its directors serve as a director of ours at the same time.

Subject to a limited exception for Jackson Electric Membership Corporation, which is the sole member of one of the member groups, the bylaw amendments continue the prohibition against any person simultaneously serving as a director of Oglethorpe and either Georgia Transmission or Georgia System Operations, and against any outside director serving as a director, officer or employee of Georgia Transmission, Georgia System Operations or any member or an officer or employee of Oglethorpe. As under the previous bylaws, 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.

We are managed and operated under the direction of a president and chief executive officer, who is appointed by our board of directors. Our executive officers and directors are as follows:

Thomas A. Smith is the President and Chief Executive Officer of Oglethorpe and has served in that capacity since September 1999. He previously served as Senior Vice President and Chief Financial Officer of Oglethorpe from September 1998 to August 1999, Senior Financial Officer from 1997 to August 1998, Vice President, Finance from 1986 to 1990, Manager of Finance from 1983 to 1986 and Manager, Financial Services from 1979 to 1983. From 1990 to 1997, Mr. Smith was Senior Vice President of the Rural Utility Banking Group of CoBank, where he managed the bank's eastern division, rural utilities. Mr. Smith is a Certified Public Accountant, has a Master of Science degree in Industrial Management-Finance from the Georgia Institute of Technology, a Master of Science degree in Analytical Chemistry from Purdue University and a Bachelor of Arts degree in Mathematics and Chemistry from Catawba College. Mr. Smith is a Director of ACES Power Marketing and is that entity's Treasurer and Chairman of their Risk Oversight and Audit Committee. Mr. Smith is also a director of the Electric Power Research Institute (EPRI) and the Georgia Chamber of Commerce. In 2009, Mr. Smith was selected to serve on the Georgia Tech Advisory Board. Mr. Smith previously served as a director of En-Touch Systems, Inc. from 2001 to 2006 and as a member of the North American Electric Reliability Corporation Stakeholders Committee from 2005 to 2006. In 2008 and 2007, Mr. Smith was named to Georgia Trend's list of the top 100 most influential Georgians. In 2003, Mr. Smith was a recipient of the Ellis Island Medal of Honor.

Michael W. Price is our Executive Vice President and Chief Operating Officer and has served in that office since February 1, 2000. In October 2008, Mr. Price's title changed from Chief Operating Officer to his current title. Mr. Price was employed by Georgia System Operations 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 Georgia Transmission from May 1997 to December 1998. He served as a manager of system control of Georgia System Operations from January to May 1997. From 1986 to 1997, Mr. Price was employed by Oglethorpe in the areas of control room operations, system planning, construction and engineering, and energy management systems. Prior to joining Oglethorpe, he was a field test engineer with the Tennessee Valley Authority from 1983 to 1986. Mr. Price has a Bachelor of Science degree in Electrical Engineering from Auburn University. Mr. Price is a director of SERC Reliability Corporation, ACES Power Marketing, the Research Advisory Committee of Electric Power Research Institute and serves on the Advisory Board of Garrard Construction.

Elizabeth B. Higgins is our Executive Vice President and Chief Financial Officer and has served in that office since July 2004. In October 2008, Ms. Higgins' title changed from Chief Financial Officer to her current title. Ms. Higgins served as Senior Vice President, Finance & Planning of Oglethorpe from July 2003 to July 2004. Ms. Higgins served as Vice President of Oglethorpe with various responsibilities including strategic planning, rates, analysis and member relations from September 2000 to July 2003. Ms. Higgins served as the Vice President and Assistant to the Chief Executive Officer of Oglethorpe from October 1999 to September 2000 and served in other capacities for Oglethorpe from April 1997 to September 1999. Prior to that, Ms. Higgins served as Project Manager at Southern Engineering from October 1995 to April 1997, as Senior Consultant at Deloitte & Touche, LLP from April 1995 to October 1995, and as Senior Consultant at Energy Management Associates from June 1991 to April 1995. In these positions, Ms. Higgins was responsible for competitive bidding analyses, rate designs, integrated resource planning studies, operational/dispatch studies, bulk power market analysis, merger analyses and litigation support. Ms. Higgins has a Bachelor of Industrial Engineering degree from the Georgia Institute of Technology and a Master of Business Administration degree from Georgia State University.

William F. Ussery is our Executive Vice President, Member and External Relations and has served in that office since October 2005. In October 2008, Mr. Ussery's title changed from Senior Vice President, Member and External Relations to his current title. Mr. Ussery previously served as Vice President and Assistant Chief Operating Officer of Oglethorpe from November 2003 to October 2005. Prior to joining Oglethorpe in 2001, Mr. Ussery held several key positions, including Chief Operating Officer, Vice President of Engineering and System Engineer at Sawnee Electric Membership Corporation. Mr. Ussery holds a bachelor's degree in Electrical Engineering from Auburn University and an associate degree in Science from Middle Georgia College.

W. Clayton Robbins is our Senior Vice President, Governmental Affairs and has served in the office since October 2008. Prior to that Mr. Robbins was Senior Vice President, Government Relations and Chief Administrative Officer from July 2006 until October 2008, and as Chief Administrative Officer from January 2006 until July 2006. He also served as Senior Vice President, Administration and Risk Management of Oglethorpe from October 2002 to December 2006; and served as Senior Vice President, Finance and Administration of Oglethorpe from November 1999 to September 2002. Mr. Robbins served as Senior Vice President and General Manager of Intellisource, Inc. from February 1997 to October 1999. Prior to that, Mr. Robbins held several senior management and executive management positions at Oglethorpe beginning in 1986. Before joining Oglethorpe, Mr. Robbins spent 18 years with Stearns-Catalytic World Corporation, a major engineering and construction firm, including 13 years in management positions responsible for human resources, information systems, contracts, insurance, accounting, and project development. Mr. Robbins has a Bachelor of Arts Degree in Business Administration from the University of North Carolina at Charlotte. Mr. Robbins serves on the advisory board of FM Global Insurance Company and on the board of Niner Wine Estates, Paso Robles, in California.

Jami G. Reusch is our 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 the Chairman of the Board and an at-large director. He has served on our board of directors since December 1988. His present term will expire in March 2010. Mr. Denham has been co-owner of Denham Farms in Turner County, Georgia since 1980. Mr. Denham is a director of Irwin Electric Membership Corporation.

Marshall S. Millwood is an at-large director. He has served on our board of directors since March 2003. His present term will expire in March 2012. He is also a member of the construction project 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 Electric Membership Corporation.

Bobby C. Smith, Jr. is an at-large director. He has served on our board of directors since May 2008. His present term will expire in March 2011. He is also a member of the construction project committee. Mr. Smith is a farmer. He is a member of the board of Planters Electric Membership Corporation. He is also a member of the board of Screven County Zoning and of the Sylvania Lions Club. Mr. Smith serves on the advisory council of the Southern States Cooperative's Statesboro Complex.

Larry N. Chadwick is a member group director (group 1). He has served on our board of directors since July 1989. His present term will expire in March 2011. He is also a member of the compensation committee. Mr. Chadwick is an engineer, with experience in the design of hydrogen gas plants. He is Chairman of the board of Cobb Electric Membership Corporation.

Gary W. Wyatt is a member group director (group 1). He has served on our board of directors since March 2004. His present term will expire in March 2010. He is also a member of the compensation committee. He started his career in 1973 with Coosa Valley Electric Co-op in Talladega, Alabama where he held the position of Operations Manager. He assumed the position of President/Chief Executive Officer of Pataula Electric Membership Corporation in 1986. Mr. Wyatt received an A.S. degree in management from Darton College. He is also a graduate of the National Rural Electric Cooperative Association Management Internship program at the University of Nebraska. He is on the board of directors of Georgia Electric Membership Corporation and is a past Vice Chairman of the Services Committee. Mr. Wyatt is the past President of the Georgia Managers Association, past Vice Chairman of the Albany Technical College Board of Directors and past President of the Randolph Cuthbert Chamber of Commerce.

H.B. Wiley, Jr. is a member group director (group 2). He has served on our board of directors since March 2003. His present term will expire in March 2012. He is also a member of the audit committee. Mr. Wiley previously served as a member of the board of directors from July 1994 until March 1997. Mr. Wiley has been an associate broker in real estate since 1994. Prior to that time, he owned and operated a dairy farm in Oconee County, Georgia from 1973 to 1994. During that time he served on the board of Atlanta Dairies Cooperative and Georgia Milk Producers Board. He has been a director of Walton Electric Membership Corporation since June 1993, and served as its Chairman of the Board from June 2000 to June 2003. Mr. Wiley has a Bachelor of Science degree from the University of Georgia. Mr. Wiley served in the U.S. Army Engineers from 1968 to 1971 and is a Vietnam veteran.

Rick L. Gaston is a member group director (group 2). He has served on our board of directors since May 2008. His present term will expire in March 2011. He is also a member of the construction project committee. Mr. Gaston is the General Manager of Colquitt Electric Membership Corporation. Mr. Gaston has also served on the board of directors of Georgia Transmission.

M. Anthony Ham is a member group director (group 3). He has served on our board of directors since March 2004. His present term will expire in March 2011. He is also a member of the compensation committee. Mr. Ham operates Tony Ham Elite Property Services. In December 2008, Mr. Ham left his position as the Clerk of the Superior and Juvenile Court in Brantley County, Georgia after 20 years of service. He is a director of Okefenoke Rural Electric Membership Corporation and was appointed Secretary and Treasurer in 2007.

C. Hill Bentley is a member group director (group 3). He has served on our board of directors since March 2004. His present term will expire in March 2010. He is also a member of the audit committee. He is the Chief Executive Officer of Tri-County Electric Membership Corporation. He is President of the Board of Directors of the Georgia Cooperative Council and a member of the board of directors of the Central Georgia Technical College Foundation. Mr. Bentley is a member of the Bibb County Chamber of Commerce and the Georgia Chamber of Commerce, and is past President of the Jones County Chamber of Commerce. Mr. Bentley is a member, and a past President, of the Georgia Rural Electric Managers Association and a member of the Rural Electric Managers Development Council and Georgia Economic Developers Association. He is also on the Business Advisory Council for Georgia College and State University.

J. Sam L. Rabun is the Vice-Chairman of the Board and a member group director (group 4). He has served on our board of directors since March 1993. His present term will expire in March 2010. He is also the chairman of the compensation committee. He has been the owner and operator of a farm in Jefferson County, Georgia since 1979. Mr. Rabun served as the President of the Board of Jefferson Energy Cooperative from 1993 to 1996, was employed as General Manager from 1974 to 1979 and as Office Manager and Accountant from 1970 to 1974. He currently serves on the board of Jefferson Energy Cooperative. Mr. Rabun is Vice-Chairman of the Board of the Georgia Energy Cooperative.

Jeffrey W. Murphy is a member group director (group 4). He has served on our board of directors since March 2004. His present term will expire in March 2012. He is also a member of the audit committee. Mr. Murphy has been the President and Chief Executive Officer of Hart Electric Membership Corporation since May 2002. He is also the Secretary of the Georgia Energy Cooperative.

G. Randall Pugh is a member group director (group 5). He has served on our board of directors since May 2008. His present term will expire in March 2011. He is also the chairman of the construction project committee. Mr. Pugh is the President and Chief Executive Officer of Jackson Electric Membership Corporation, prior to which he served as General Manager of Walton Electric Membership Corporation. He is Chairman of the Board of First Georgia Banking Company (Jackson and Banks County) and Chairman of the Georgia System Operations Audit Committee. He also serves on the Board of Directors of First Georgia Bankshares Holding Company, Green Power Electric Membership Corporation and Georgia System Operations. He is a past director and Chairman of the Board of Directors of Regions Bank (Jackson County). Mr. Pugh is a member of the Executive Board of the Northeast Georgia Council of the Boy Scouts of America. He is a member of the board and serves as Chairman of the Jackson County, Georgia, Water and Sewer Authority. He also is a member and past President of the Jackson County Chamber of Commerce and of the Jefferson Rotary Club.

Wm. Ronald Duffey is an outside director. He has served on our board of directors since March 1997. His present term will expire in March 2012. He is also the chairman of the audit committee. Mr. Duffey is the retired Chairman of the Board of Directors of Peachtree National Bank in Peachtree City, Georgia, a wholly owned subsidiary of Synovus Financial Corp., and now serves as Chair of the Advisory Board of the Bank of North Georgia—Fayette. Prior to his employment in 1985

with Peachtree National Bank, Mr. Duffey served as Executive Vice President and Member of the Board of Directors for First National Bank in Newnan, Georgia. He holds a Bachelor of Business Administration from Georgia State College with a concentration in finance and has completed banking courses at the School of Banking of the South, Louisiana State University, the American Bankers Association School of Bank Investments, and The Stonier Graduate School of Banking, Rutgers University. Mr. Duffey is a director of Piedmont-Fayette Hospital, Piedmont-Newnan Hospital and The Georgia Economic Development Corp. Mr. Duffey is also a member of the board of directors of the Georgia Chamber of Commerce and of the audit committee of Piedmont Healthcare.

Our board of directors has established an audit committee, a compensation committee and a construction project committee. The audit committee, the compensation committee and the construction project committee each operate pursuant to a committee charter and/or policy. We do not have a nominating and corporate governance committee; directors are nominated by representatives from each member whose weighted nomination is based on the number of retail customers served by each member, and after nomination, elected by a majority vote of the members, voting on a one-member, one-vote basis.

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

Compensation Committee. The compensation committee is responsible for monitoring adherence with our compensation programs and recommending changes to its compensation programs as needed. The members of the compensation committee are J. Sam L. Rabun, Gary W. Wyatt, M. Anthony Ham and Larry N. Chadwick.

Construction Project Committee. The construction project committee is responsible for reviewing, and making recommendations with regards to, major actions or commitments relating to new power plant construction projects and certain existing plant modification projects. Its responsibilities include reviewing and recommending final plant sites, project budgets (including certain modifications to project budgets) and project construction plans, and a quarterly reviewing of and reporting on the status of projects. The members of the construction project committee are currently G. Randall Pugh, Rick L. Gaston, Marshall S. Millwood and Bobby C. Smith, Jr. Mr. Pugh is the chairman of the construction project committee.

The following table sets forth the total compensation paid or earned by each of our directors for the fiscal year ended December 31, 2008.

During 2008, we paid our outside directors a fee of $5,500 per board meeting for four meetings a year and a fee of $1,000 per board meeting for the remaining other board meetings held during the year. Outside directors were also paid $1,000 per day for attending committee meetings, annual meetings of the members or other official business of ours. Member directors were paid a fee of $1,200 per board meeting and $800 per day for attending committee meetings, other meetings except annual meetings of the members, or other official business of ours approved by the chairman of the board of directors. Member directors are paid $600 per day for attending the annual meeting of members and member advisory board meetings. In addition, we reimburse all directors for out-of-pocket expenses incurred in attending a meeting. All directors are paid $100 per day when participating in meetings by conference call. The chairman of the board of directors is paid an additional 20% of his director's fee per board meeting for time involved in preparing for the meetings. The chairman of the audit committee is paid an additional $400 per audit committee meeting for the time involved in fulfilling that role. Neither our outside directors nor member directors receive any perquisites or other personal benefits.

The compensation committee of the board of directors has responsibility for establishing, implementing and monitoring adherence with our compensation programs.

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

Components of Total Compensation. The compensation committee determined that compensation packages for the fiscal year ended December 31, 2008 for our executive officers should be comprised of the following three primary components:

Base Salary. Base salary is designed to attract and retain executives who can assist us in meeting our corporate goals. We believe that executive officer base salaries should be compared to the median of the range of salaries for executives in similar positions and with similar responsibilities at comparable companies. Base salary is established, in part, by surveying the external market. The compensation committee and our president and chief executive officer also factor in corporate performance and changes in individuals' roles and responsibilities when making decisions regarding executive officers' base salaries.

Each of our executive officers has an employment agreement that provides for a minimum annual base salary and performance pay. See the narrative disclosure following the "Summary Compensation Table" below for additional information on the terms of the employment agreements.

Performance Pay. Performance pay is designed to reward executive officers based on our success in achieving the corporate goals discussed below. Each executive officer has the potential to earn 20% of their base pay in performance pay. Each executive officer's performance pay award for 2008 was based 100% on the achievement of corporate goals, as determined by the board of directors upon the compensation committee's recommendation.

Benefits. The benefits program is designed to allow executive officers to choose the benefit options that best meet their needs. Our president and chief executive officer recommends changes to the benefits program or level of benefits that all executive officers, including our president and chief executive officer, receive to the compensation committee. The compensation committee then reviews and recommends changes to the board of directors for its approval. To meet the health and welfare needs of its executive officers at a reasonable cost, we pay for 80-85% of an executive officer's health and welfare benefits. Our president and chief executive officer decides our exact cost sharing percentage.

We also provide retirement benefits that allow executive officers the opportunity to develop an investment strategy that best meets their retirement needs. We will contribute up to $0.75 of every dollar an executive officer contributes to his or her retirement plan, up to 6% of an executive officer's pay per period, and will contribute an additional amount equal to 8% of an executive officer's pay per period. See "Nonqualified Deferred Compensation" below for additional information regarding our contributions to our executive officers' retirement plans.

Perquisites. We provide our executive officers with perquisites that we and the compensation committee believe are reasonable and consistent with our overall compensation program. The most significant perquisite provided to our executive officers is a monthly car allowance, the amount of which is based upon the executive officer's position. Our president and chief executive officer approves the executive officers eligible for car allowances and reports this information to the compensation committee. The car allowance for our president and chief executive officer is included in his employment agreement. The compensation committee periodically reviews the levels of perquisites provided to executive officers.

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

The compensation committee operates pursuant to a statement of functions that sets forth the committee's objectives and responsibilities. The compensation committee's objective is to review and recommend to the board of directors for approval any changes to various compensation related matters, as well as any significant changes in benefits cost or level of benefits, for the members of the board of directors, the executive officers, and our other employees. The compensation committee annually reviews the statement of functions and makes any necessary revisions to ensure its responsibilities are accurately stated.

Role of Management. The key member of management involved in the compensation process is our president and chief executive officer. Our president and chief executive officer, together with the other executive officers, identifies corporate performance objectives that are used to determine performance pay amounts. Our president and chief executive officer and our vice president, human resources present these goals to the compensation committee. The compensation committee then reviews and approves the goals and presents them to the board of directors for review and approval. Our president and chief executive officer approves the compensation of our executive officers, other than the president and chief executive officer, and in certain circumstances provides an upward adjustment to the executive officers' base salary. The president and chief executive officer reports the executive officers' salaries to the compensation committee annually. Our president and chief executive officer's compensation is approved by the board of directors upon recommendation of the compensation committee.

Role of the Compensation Consultant. We engage a compensation consultant to assist us in reviewing our compensation program on a periodic basis. During 2006, we engaged Hewitt Associates, an outside global human resources consulting firm, to conduct a review of our compensation program. Hewitt Associates provided us with relevant market data that was used to analyze our compensation program in light of the compensation programs of our peers and also to ensure that our compensation program aligned with our stated compensation philosophy and objectives. We did not engage a compensation consultant during 2008.

To remain competitive, we annually validate each component of total compensation paid to the executive officers relative to market values for compensation paid to similarly situated executives at companies we consider to be our peers. We refer to this practice as benchmarking and do not consider it the determinative factor in setting executive officers' compensation. Rather, we intend for benchmarking to supplement our other internal analyses regarding individual's performance in prior

years and achievement of corporate goals that we consider when determining the performance pay component of executive officers' compensation.

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

For 2008, our peer group was composed of the companies included in the utilities industry sector reported in the U.S. Mercer Benchmark Survey, the 2008 Towers Perrin Executive Energy Survey, the companies included in the Utilities & Energy industry sector of the Watson Wyatt Top Management Report and the 2008 National Rural Electric Cooperative Association Generation and Transmission Compensation Survey. Although there is a large variance in the size of the companies included in these surveys, we believe they serve as appropriate comparisons to us because they are in the utility industry. Therefore, these companies likely have operations similar to ours and executives who have responsibilities and perform roles similar to our executives. In addition, these are the companies with whom we primarily compete for executive talent.

The Mercer Benchmark Executive Survey includes 2,579 participants from a broad range of industry sectors with annual revenues ranging from $256 million to $23 billion annually. We focus our comparison on utilities sector participants with annual revenues ranging from $1 billion to $3 billion annually. We focused our comparison on these companies because they are most similar to us in terms of industry sector and revenues.

The Towers Perrin Executive Energy Survey includes 90 participant companies with revenues ranging from less than $1 billion to greater than $6 billion annually. We typically focus on the 24 participant companies that have revenues ranging from $1 billion to $3 billion when reviewing executive level compensation. We choose to focus on these companies because their revenues are most similar to ours.

The Watson Wyatt Top Management Report includes 1,503 participants from a variety of industries. We focus on the participant companies from the utilities and energy sectors.

The 2008 National Rural Electric Cooperative Association Generation and Transmission Compensation Survey includes 50 companies, including us, all of whom are its members. Although we believe compensation paid to executives at other electric cooperatives is a relevant comparison tool, we do not focus exclusively on these companies when benchmarking compensation because we are larger than most of the other companies included in this survey.

Each of our executive officers is entitled to certain severance payments and benefits in the event they are terminated not for cause or they resign for good reason. We negotiated each employment agreement with the executive officers on an arms-length basis, and the compensation committee determined that the terms of each agreement are reasonable and necessary to ensure that our executive officers' goals are aligned with ours and that each performs his or her respective role while acting solely in our best interests. See "Severance Arrangements" below for a discussion of the terms of each of the president and chief executive officer's and other executive officers' agreements.

The compensation committee last reviewed the president and chief executive officer's employment agreement in November 2008. In determining that the president and chief executive officer's employment agreement was appropriate and necessary, the compensation committee considered Mr. Smith's role and responsibility within Oglethorpe in relation to the total amount of severance pay he would receive upon the occurrence of a severance event. The committee also considered whether the amount Mr. Smith would receive upon severance was appropriate given his total annual compensation.

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

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

Each year we draft a comprehensive set of corporate goals which are approved by the board of directors. For 2008, our corporate goals primarily involved the following: (i) the operation of our plants by facility type, (ii) our financial performance for the year, including cost savings and risk reduction programs, (iii) quality of performance, (iv) environmental compliance, (v) safety and (vi) corporate compliance.

We chose to tie performance compensation to these corporate goals because they most appropriately measure what we aim to accomplish. For us to be successful we must perform sound asset management by acquiring and managing the power supply resources necessary to serve our customers effectively. To do this, we must operate efficiently, safely, and in a financially sound manner that meets the expectations of our members, as represented by our board of directors. We review these corporate goals annually and makes adjustments as needed to ensure that we are consistently stretching our goal expectations.

Performance pay paid to our executive officers is determined based on our success in achieving each of the goals identified above. Our board of directors annually approves a weighted system for determining performance pay whereby we assign a percentage to each of the goals identified above. At the end of each fiscal year, we determine goal achievement for each of the five categories. Based on the achievement for each category, we assign a percentage, up to the maximum percentage allowed for each category, to determine the amount of performance pay available to our executive officers. For each executive officer, we then multiply 20% of his or her base salary by the goal achievement percentage amount. For example, if we had a 90% corporate goal achievement rate in a given year, each executive officer's performance pay would equal (base salary × 20%) × (90%). Set forth below is

a chart summarizing our corporate goal weighting system for 2008 as approved by our board of directors in February 2008:

We measure goal achievement in each of the above categories as follows: We base our operations achievements on how well each of our operating plants respond to system requirements. In reviewing our success in meeting our financial goals, we consider what cost savings and cost reduction programs are implemented in a given year that will result in cost savings either in the current year or on a long-term basis. We also consider whether any programs were implemented that may not have resulted in cost savings in the current year, but nonetheless increased the value of our assets or reduced potential risk. We measure our quality goal performance based on the performance appraisal of the members, as represented by the board of directors. Environmental compliance is measured by considering whether we have received notices of violation or letters of noncompliance, or had any spills at any of our facilities. Safety performance is measured by reviewing our standards and the safety of our work environment against those of other electric utilities. Corporate compliance is measured by considering whether we have received any violations under the Mandatory Electric Reliability Standard from North American Electric Reliability Corporation/Southeastern Electric Reliability Council.

As explained above, in identifying prevailing market compensation for similarly situated companies, we consider market data as well as achievement of corporate and individual goals. In determining individual compensation for our executive officers, the compensation committee considers the total compensation awarded to each individual, and a percentage of each executive officer's annual compensation is based on corporate performance. This approach allows us to maintain the flexibility necessary to differentiate pay in recognition of corporate performance.

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

In 2008, our corporate goal achievement was 85.7%. Goal achievement rate by category based on the weighted system identified above was as follows:

We achieved 85.7% of our corporate goals for 2008 primarily because we met all of our financial, environmental compliance, and safety goals. With respect to operations, we generally exceeded our threshold targets with all but a few of the facilities achieving maximum targets. As a result of achieving 85.7% of our corporate goals for 2008, each of our executive officers received performance pay in an amount equal to 85.7% of 20% of his or her base salary. Set forth below is a table showing 2008 performance pay figures for each of our executive officers:

J. Sam L. Rabun, Gary A. Miller, Gary W. Wyatt, M. Anthony Ham and Larry N. Chadwick served as members of our compensation committee in 2008. J. Sam L. Rabun served as the Vice Chairman of the board of directors in 2008.

Gary A. Miller was a director of ours and the president and chief executive officer of GreyStone Power Corporation. GreyStone Power is a member of ours and has a wholesale power contract with us. GreyStone Power's payments of $86.0 million to us in 2008 under the wholesale power contract accounted for approximately 6.9% of our total revenues.

Gary W. Wyatt is a director of ours and the president and chief executive officer of Pataula Electric Membership Corporation. Pataula is a member of ours and has a wholesale power contract with us. Pataula's payments of $2.4 million to us in 2008 under the wholesale power contract accounted for less than 1% of our total revenues.

The following table sets forth the total compensation paid or earned by each of our executive officers for the fiscal years ended December 31, 2008, 2007 and 2006.

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

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

Effective January 1, 2007, we entered into employment agreements with Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch. Each agreement extends through December 31, 2009, and automatically renews for successive one-year periods unless either party provides written notice not to renew the agreement on or before November 30, 2007 (for the initial term) or thirteen months before the expiration of any extended term. No such notices have been provided. Minimum annual base salaries under the 2007 agreements are $255,116 for Mr. Price, $246,887 for Ms. Higgins, $171,700 for Mr. Ussery, $164,000 for Mr. Robbins, and $148,596 for Ms. Reusch. Salaries are subject to review and possible upward adjustment as determined by the president and the chief executive officer. Each executive is also eligible for an annual bonus or other incentive compensation plans generally available to similarly situated employees, determined by us in our sole discretion. The employment agreements with Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins, and Ms. Reusch contain severance pay provisions. Details regarding the severance pay provisions of the agreements are provided under "Severance Arrangements."

The following table sets forth certain information with respect to the performance pay for the fiscal year ended December 31, 2008 awarded to the executive officers listed in the Summary Compensation Table.

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

We maintain a Fidelity Non-Qualified Deferred Compensation Program. The non-qualified deferred compensation program serves as a vehicle through which we can continue our employer retirement contributions to our executive officers beyond the IRS salary limits on the retirement plan ($230,000 as indexed). The following table sets forth our contributions for the fiscal year ended December 31, 2008 along with aggregate earnings for the same period.

Pursuant to the terms of his employment agreement, Mr. Smith will be entitled to a lump-sum severance payment upon the occurrence of any of the following events: (1) we terminate Mr. Smith's employment without cause; or (2) Mr. Smith resigns due to a demotion or material reduction of his position or responsibilities, reduction of his base salary, or a relocation of Mr. Smith's principal office by more than 50 miles. The severance payment will equal Mr. Smith's base salary through the rest of the term of the agreement (with a minimum of one year's pay and a maximum of two years' pay), and is payable within 30 days of termination, subject to the provisions of Internal Revenue Code

Section 409A. In addition, Mr. Smith will be entitled to outplacement services we provide and an amount equal to Mr. Smith's costs for medical and dental continuation coverage under COBRA, each for the longer of one year or the remaining term of the agreement. Severance is payable only if Mr. Smith signs a form releasing all claims against us within 45 days after his termination date. The maximum severance that would be payable to Mr. Smith in the circumstances described above is $1,217,307.

Pursuant to the terms of their employment agreements, Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins, and Ms. Reusch will each be entitled to a lump-sum severance payment if we terminate the executive without cause or if the executive resigns after a demotion or material reduction of his or her position or responsibilities, a reduction of his or her base salary, or a relocation of his or her principal office by more than 50 miles. The severance payment will equal the one year of the executive's base salary, payable six months after the executive's termination date. In addition, the executive will be entitled to six months of outplacement services we provide and an amount equal to the executive's cost for medical and dental continuation coverage under COBRA for six months. Severance is payable only if the executive signs a form releasing all claims against us within 45 days after his or her termination date. The maximum severance that would be payable to Mr. Price, Ms. Higgins, Mr. Ussery, Mr. Robbins and Ms. Reusch in the circumstances described above is $354,751, $354,504, $274,791, $235,490 and $182,330, respectively.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Jeffrey W. Murphy is a director of ours and the President and Chief Executive Officer of Hart Electric Membership Corporation. Hart Electric Membership Corporation is a member of Oglethorpe and has a wholesale power contract with Oglethorpe. Hart Electric Membership Corporation's revenues of $22.4 million to Oglethorpe in 2008 under the wholesale power contract accounted for approximately 1.8% of our total revenues.

Gary A. Miller was a director of ours through March 2009 and he is 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 revenues of $86.0 million to Oglethorpe in 2008 under the wholesale power contract accounted for approximately 6.9% of our total revenues.

C. Hill Bentley is a director of ours and the Chief Executive Officer of Tri-County Electric Membership Corporation. Tri-County Electric Membership Corporation is a member of Oglethorpe and has a wholesale power contract with Oglethorpe. Tri-County Electric Membership Corporation's revenues of $14.2 million to Oglethorpe in 2008 under the wholesale power contract accounted for approximately 1.1% of our total revenues.

Gary W. Wyatt is a director of ours and the President and Chief Executive Officer of Pataula Electric Membership Corporation. Pataula Electric Membership Corporation is a member of Oglethorpe and has a wholesale power contract with Oglethorpe. Pataula Electric Membership Corporation's revenues of $2.4 million to Oglethorpe in 2008 under the wholesale power contract accounted for less than 1% of our total revenues and Pataula Electric Membership Corporation is owned by another member of Oglethorpe, Cobb Electric Membership Corporation.

Rick Gaston is a director of ours and the General Manager of Colquitt Electric Membership Corporation. Colquitt Electric Membership Corporation is a member of Oglethorpe and has a wholesale power contract with Oglethorpe. Colquitt Electric Membership Corporation's revenues of $33.6 million to Oglethorpe in 2008 under the wholesale power contract accounted for approximately 2.7% of our total revenues.

Randall Pugh is a director of ours and the President and Chief Executive Officer of Jackson Electric Membership Corporation. Jackson Electric Membership Corporation is a member of Oglethorpe and has a wholesale power contract with Oglethorpe. Jackson Electric Membership Corporation's revenues of $141.0 million to Oglethorpe in 2008 under the wholesale power contract accounted for approximately 11.4% of our total revenues.

We have a Standards of Conduct/Conflict of Interest policy that sets forth guidelines that our employees and directors must follow in order to avoid conflicts of interest, or any appearance of conflicts of interest, between an individual's personal interests and our interests. Pursuant to this policy, each employee and director must disclose any conflicts of interest, actions or relationships that might give rise to a conflict. Our president and chief executive officer is responsible for taking reasonable steps to ensure that the employees are complying with this policy and the audit committee is responsible for taking reasonable steps to ensure that the directors are complying with this policy. The audit committee is charged with monitoring compliance with this policy and making recommendations to the board of directors regarding this policy. Certain actions or relationships that might give rise to a conflict of interest are reviewed and approved by the board of directors.

Because we are an electric cooperative, the members we serve own and manage us. Our bylaws, which were amended on May 1, 2008, set forth specific requirements regarding the composition of our board of directors. Pursuant to the bylaw amendments, our board of directors will continue to be comprised of member directors and up to two outside directors. Rather than dividing the member director positions among five geographical regions as the previous bylaws had done, the bylaw amendments divide member director positions among five member groups. Similar to the previous bylaws, member director positions are provided for a general manager of a member in each member group and a director of a member in each member group. The bylaw amendments permit expansion of the number of member groups and changes in the composition of member groups. Formation of new member groups and changes in the composition of member groups are subject to certain required member approvals, and the requirement that the composition of the member groups at Oglethorpe, Georgia Transmission and Georgia System Operations be identical, except in cases where a member is no longer a member of one or more of Oglethorpe, Georgia Transmission or Georgia System Operations. The number of member director positions will change if additional member groups are formed or a member group ceases to exist. The bylaw amendments also expand the number of at-large member director positions from one to three and provide for these to be filled by a director of a member.

In addition to meeting the requirements set forth in our bylaws, all directors, with the exception of Gary A. Miller, whose term expired on March 31, 2009, and Randall Pugh, satisfy the definition of director independence as prescribed by the NASDAQ Stock Market and otherwise meet the requirements set forth in our bylaws. Gary A. Miller did not qualify as an independent director because he is the President and Chief Executive Officer of GreyStone Power Corporation, which accounted for approximately 6.9% of our revenues for the fiscal year ended December 31, 2008. Randall Pugh also does not qualify as an independent director because he is the President and Chief Executive Officer of Jackson Electric Membership Corporation, which accounted for approximately 11.4% of our revenues for the fiscal year ended December 31, 2008. Although we do not have any securities listed on the NASDAQ Stock Market, we have used the NASDAQ Stock Market's independence criteria in making this determination in accordance with applicable SEC rules.

The original bonds were sold to the initial purchasers on February 19, 2009 in a private offering pursuant to a purchase agreement. The initial purchasers subsequently sold the original bonds to qualified institutional buyers (as defined in Rule 144A under the Securities Act) in reliance on Rule 144A.

In connection with the sale of the original bonds, we entered into a registration rights agreement with J.P. Morgan Securities Inc., as representative of the initial purchasers, in which we agreed to file an exchange offer registration statement relating to an offer to exchange the original bonds for exchange bonds and to use our reasonable best efforts to:

The exchange bonds will have terms substantially identical to the original bonds, except that the exchange bonds will not contain terms with respect to transfer restrictions and additional interest for failure to observe certain obligations in the registration rights agreement. The original bonds were issued on February 19, 2009.

Under the circumstances set forth below, we will use our reasonable best efforts to cause the SEC to declare effective a shelf registration statement with respect to the resale of the original bonds within the time periods specified in the registration rights agreement and keep the shelf registration statement effective for one year after the issuance date of the original bonds or such shorter period terminating when all of the registrable securities (as defined below) covered by the shelf registration statement have been sold pursuant to the shelf registration statement. These circumstances include:

then, as liquidated damages, during the registration default period, the interest rate on the registrable securities, payable to the holders of the registrable securities, will be increased by 1.00% per annum until the registration default is remedied; however, no registration default period shall continue more than one year from the issuance date of the original bonds.

If the exchange offer registration statement or the shelf registration statement has been declared effective and such registration statement ceases to be effective or the prospectus contained therein becomes unusable for more than 30 days prior to the 180^th day after the expiration date of the exchange offer in the case of an exchange offer registration statement being used by a broker-dealer or the first anniversary of the issuance date of the original bonds in the case of a shelf registration statement, then, beginning on the 31^st day, interest shall accrue on the principal amount of the affected bonds at a rate of 1.00% per annum over the interest rate otherwise provided for under the original bonds until the applicable registration statement has again become effective, the prospectus contained therein again becomes usable, or in the case of an exchange offer registration statement being used by a broker-dealer, 180 days after the expiration date of the exchange offer or in the case of a shelf registration statement, on the first anniversary of the date the original bonds were issued.

Importantly, the interest rate on the registrable securities will not increase more than 1.00% per annum because more than one registration default or other event described above has occurred and is continuing.

As defined in the registration rights agreement, registrable securities means the original bonds until the earliest to occur of (i) the date a person, other than a broker-dealer who acquired original bonds as a result of market-making or other trading activities, exchanges the original bonds for exchange bonds, (ii) in the case of a broker-dealer who acquired original bonds as a result of market-making or other trading activities, the date the exchange bonds are sold to a purchaser in accordance with this prospectus, (iii) the date on which the original bonds have been registered under the Securities Act and disposed of pursuant to a shelf registration statement, or (iv) one year from the issue date, or such earlier date if the original bonds become freely transferable as provided by Rule 144 under the Securities Act.

If you wish to exchange your original bonds for exchange bonds in the exchange offer, you will be required to make the following written representations:

Each broker-dealer that receives exchange bonds for its own account in exchange for original bonds, where the broker-dealer acquired the original bonds as a result of market-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such exchange bonds and that it did not purchase its original bonds from us or any of our affiliates. See "PLAN OF DISTRIBUTION."

Based on interpretations by the SEC set forth in no-action letters issued to third parties, we believe that you may resell or otherwise transfer the exchange bonds issued in the exchange offer without complying with the registration and prospectus delivery provisions of the Securities Act if:

If you are our affiliate, or are engaging in, or intend to engage in, or have any arrangement or understanding with any person to participate in, a distribution of the exchange bonds, or are not acquiring the exchange bonds in the ordinary course of your business:

This prospectus may be used for an offer to resell, resale or other transfer of exchange bonds only as specifically set forth in this prospectus. With regard to broker-dealers, only broker-dealers that acquired original bonds as a result of market-making activities or other trading activities may participate in the exchange offer. Each broker-dealer that receives exchange bonds for its own account in exchange for original bonds, where such original bonds were acquired by such broker-dealer as a result of marketing-making activities or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of the exchange bonds. Read "PLAN OF DISTRIBUTION" for more details regarding the transfer of exchange bonds.

Our belief that the exchange bonds may be offered for resale without compliance with the registration or prospectus delivery provisions of the Securities Act is based on interpretations of the SEC for other exchange offers that the SEC expressed in some of its no-action letters to other issuers in exchange offers like ours. We cannot guarantee that the SEC would make a similar decision about our exchange offer. If our belief is wrong, or if you cannot truthfully make the representations mentioned above, and you transfer any exchange bond issued to you in the exchange offer without meeting the registration and prospectus delivery requirements of the Securities Act, or without an exemption from such requirements, you could incur liability under the Securities Act. We will not indemnify you for any such liability.

On the terms and subject to the conditions set forth in this prospectus and in the accompanying letter of transmittal, we will accept for exchange in the exchange offer any original bonds that are validly tendered and not validly withdrawn prior to the expiration date of the exchange offer. Original bonds may only be tendered in minimum denominations of $1,000 and integral multiples of $1,000. We will issue exchange bonds in principal amounts identical to original bonds surrendered in the exchange offer.

The form and terms of the exchange bonds will be substantially identical to the form and terms of the original bonds except the exchange bonds will be registered under the Securities Act, will not bear legends restricting their transfer and will not provide for any additional interest upon our failure to fulfill our obligations under the registration rights agreement. The exchange bonds will evidence the same debt as the original bonds. The exchange bonds will be issued under and entitled to the benefits of the indenture. For a description of the indenture, see "SUMMARY OF THE INDENTURE."

The exchange offer is not conditioned upon any minimum aggregate principal amount of original bonds being tendered for exchange.

As of the date of this prospectus, $350,000,000 aggregate principal amount of the 6.10% First Mortgage Bonds, Series 2009 A due 2019 are outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of original bonds. There will be no fixed record date for determining registered holders of original bonds entitled to participate in the exchange offer. We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Exchange Act and the rules and regulations of the SEC. Original bonds that are not tendered for exchange in the exchange offer will remaining outstanding and continue to accrue interest and will be entitled to the rights and benefits such holders have under the indenture except we will not have any further obligation to provide for the registration of the original bonds under the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered original bonds when we have given oral or written notice of the acceptance to the exchange agent. The exchange agent will act as agent for the tendering holders for the purposes of receiving the exchange bonds from us and delivering exchange bonds to holders. Subject to the terms of the registration rights agreement, we expressly reserve the right to amend or terminate the exchange offer and to refuse to accept the occurrence of any of the conditions specified below under "Conditions to the Exchange Offer."

If you are a broker-dealer and receive exchange bonds for your own account in exchange for original bonds that you acquired as a result of market-making activities or other trading activities, you must acknowledge that you will deliver this prospectus in connection with any resale of the exchanges bonds and that you did not purchase your original bonds from us or any of our affiliates. See "PLAN OF DISTRIBUTION" for more details regarding the transfer of exchange bonds.

We make no recommendation to you as to whether you should tender or refrain from tendering all or any portion of your original bonds into this exchange offer. In addition, no one has been authorized to make this recommendation. You must make your own decision whether to tender into this exchange offer and, if so, the aggregate amount of original bonds to tender after reading this prospectus and the letter of transmittal and consulting with your advisors, if any, based on your financial position and requirements.

The exchange offer expires at 5:00 p.m., New York City time on July 9, 2009, which we refer to as the expiration date. However, if we, in our sole discretion, extend the period of time for which the exchange offer is open, the term expiration date will mean the latest date to which we shall have extended the expiration of the exchange offer.

To extend the period of time during which the exchange offer is open, we will notify the exchange agent of any extension by oral or written notice, followed by notification by press release or other public announcement to the registered holders of the original bonds no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

Any delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice to the registered holders of the original bonds. If we amend the exchange offer in a manner that we determine to constitute a material change, or if we waive a material condition to the exchange offer, we will promptly disclose the amendment in a manner reasonably calculated to inform the holders of applicable original bonds of that amendment.

In the event we terminate the exchange offer, all original bonds previously tendered and not accepted for exchange will be returned promptly to the tendering holders.

Despite any other term of the exchange offer, we will not be required to accept for exchange, or to issue exchange bonds in exchange for, any original bonds and we may terminate or amend the exchange offer as provided in this prospectus prior to the expiration date if in our reasonable judgment:

In addition, we will not be obligated to accept for exchange the original bonds of any holder that has not made to us:

We expressly reserve the right at any time or at various times to extend the period of time during which the exchange offer is open. Consequently, we may delay acceptance of any original bonds by giving oral or written notice of such extension to the holders. We will return any original bonds that we do not accept for exchange for any reason without expense to the tendering holder promptly after the expiration or termination of the exchange offer. We also expressly reserve the right to amend or terminate the exchange offer and to reject for exchange any original bonds not previously accepted for exchange, if we determine that any of the conditions of the exchange offer specified above have not been satisfied. We will give oral or written notice of any extension, amendment, non-acceptance or

termination to the holders of the original bonds as promptly as practicable. In the case of any extension, such notice will be issued no later than 9:00 a.m., New York City time, on the next business day after the previously scheduled expiration date.

We reserve the right to waive any defects, irregularities or conditions to the exchange as to particular original bonds. These conditions are for our sole benefit, and we may assert them regardless of the circumstances that may give rise to them or waive them in whole or in part at any or at various times prior to the expiration of the exchange offer in our sole discretion. If we fail at any time to exercise any of the foregoing rights, this failure will not constitute a waiver of such right. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the exchange offer.

In addition, we will not accept for exchange any original bonds tendered, and will not issue exchange bonds in exchange for any such original bonds, if at such time any stop order is threatened or in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture under the Trust Indenture Act of 1939.

To tender your original bonds in the exchange offer, you must comply with either of the following:

The term "agent's message" means a message transmitted by DTC, received by the exchange agent and forming part of the book-entry confirmation, which states that:

Your tender, if not withdrawn prior to the expiration date, constitutes an agreement between us and you upon the terms and subject to the conditions described in this prospectus and in the letter of transmittal.

The method of delivery of original bonds, letters of transmittal and all other required documents to the exchange agent is at your election and risk. Delivery of such documents will be deemed made only when actually received by the exchange agent. We recommend that instead of delivery by mail, you use an overnight or hand delivery service, properly insured. If you determine to make delivery by mail, we suggest that you use properly insured, registered mail with return receipt requested. In all cases, you should allow sufficient time to assure timely delivery to the exchange agent before the expiration of the exchange offer. Letters of transmittal and certificates representing original bonds should be sent only to the exchange agent, and not to us or to any book-entry transfer facility. No alterative, conditional or contingent tenders of original bonds will be accepted. You may request that your broker, dealer, commercial bank, trust company or nominee effect the above transactions for you.

If you are a beneficial owner whose original bonds are registered in the name of a broker, dealer, commercial bank, trust company or other nominee and you wish to tender your original bonds, you should promptly contact the registered holder and instruct the registered holder to tender on your behalf. If you wish to tender the original bonds yourself, you must, prior to completing and executing the letter of transmittal and delivering your original bonds either:

The transfer of registered ownership may take considerable time and may not be able to be completed prior to the expiration of the exchange offer.

Signatures on the letter of transmittal or a notice of withdrawal (as described below in "Withdrawal Rights"), as the case may be, must be guaranteed by a firm or other entity identified in Rule 17Ad-15 under the Exchange Act as an "eligible guarantor institution," including (as such terms are defined therein) (i) a bank, (ii) a broker, dealer, municipal securities broker or dealer, (iii) a credit union, (iv) a national securities exchange, registered securities association or clearing agency or (v) a savings association that is a participant in a Securities Transfer Association, unless the original bonds are surrendered:

If the letter of transmittal is signed by a person other than the registered holder of any original bonds listed on the original bonds, such original bonds must be endorsed or accompanied by a properly completed bond power. The bond power must be signed by the registered holder as the registered holder's name appears on the original bonds, and an eligible guarantor institution must guarantee the signature on the bond power.

If the letter of transmittal, any certificates representing original bonds or bond powers are signed by trustees, executors, administrators, guardians, attorneys-in-fact, officers of corporations or others acting in a fiduciary or representative capacity, those persons should also indicate when signing and, unless waived by us, they should also submit evidence satisfactory to us of their authority to so act.

The exchange agent and DTC have confirmed that any financial institution that is a participant in DTC's system may use DTC's automated tender offer program to tender original bonds. Participants in the program may, instead of physically completing and signing the letter of transmittal and delivering it to the exchange agent, electronically transmit their acceptance of original bonds for exchange by causing DTC to transfer the original bonds to the exchange agent in accordance with DTC's automated tender offer program procedures for transfer. DTC will then send an agent's message to the exchange agent.

Promptly after the date of this prospectus, the exchange agent will establish an account with respect to the original bonds at DTC, as the book-entry transfer facility, for purposes of the exchange offer. Any financial institution that is a participant in the book-entry transfer facility's system may make book-entry delivery of the original bonds by causing the book-entry transfer facility to transfer those original bonds into the exchange agent's account at the facility in accordance with the facility's procedures for such transfer. To be timely, book-entry delivery of original bonds requires receipt of a confirmation of a book-entry transfer, or a "book-entry confirmation," prior to the expiration date.

In addition, in order to receive exchange bonds for tendered original bonds, an agent's message in connection with a book-entry transfer into the exchange agent's account at the book-entry transfer facility or the letter of transmittal or a manually signed facsimile thereof, together with any required signature guarantees and any other required documents must be delivered or transmitted to and received by the exchange agent at its address set forth on the cover page of the letter of transmittal prior to the expiration of the exchange offer. Holders of original bonds who are unable to deliver confirmation of the book-entry tender of their original bonds into the exchange agent's account at the book-entry transfer facility or all other documents required by the letter of transmittal to the exchange agent prior to the expiration of the exchange offer must tender their original bonds according to the guaranteed delivery procedures described below. Tender will not be deemed made until such documents are received by the exchange agent. Delivery of documents to the book-entry facility does not constitute delivery to the exchange agent.

If you wish to tender your original bonds but your original bonds are not immediately available or you cannot deliver your original bonds, the letter of transmittal or any other required documents to the exchange agent or comply with the procedures under DTC's automatic tender offer program in the case of original bonds, prior to the expiration date, you may still tender if:

Upon request, the exchange agent will send to you a notice of guaranteed delivery if you wish to tender your original bonds according to the guaranteed delivery procedures.

In all cases, we will promptly issue exchange bonds for original bonds that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

In addition, each broker-dealer that is to receive exchange bonds for its own account in exchange for original bonds must represent that such original bonds were acquired by that broker-dealer as a result of market-making activities or other trading activities and must acknowledge that it will deliver a prospectus that meets the requirements of the Securities Act in connection with any resale of the exchange bonds. The letter of transmittal states that by so acknowledging and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act. See "PLAN OF DISTRIBUTION."

We will interpret the terms and conditions of the exchange offer, including the letter of transmittal and the instructions to the letter of transmittal, and will resolve all questions as to the validity, form, eligibility, including time of receipt, and acceptance of original bonds tendered for exchange. Our determinations in this regard will be final and binding on all parties. We reserve the absolute right to reject any and all tenders of any particular original bonds not properly tendered or to not accept any particular original bonds if the acceptance might, in our or our counsel's judgment, be unlawful. We also reserve the absolute right to waive any defects or irregularities as to any particular original bonds prior to the expiration of the exchange offer.

Unless waived, any defects or irregularities in connection with tenders of original bonds for exchange must be cured within such reasonable period of time as we determine. Neither we, the exchange agent nor any other person will be under any duty to give notification of any defect or irregularity with respect to any tender for original bonds for exchange, nor will any of them incur any liability for any failure to give notification. Any certificates representing original bonds received by the exchange agent that are not properly tendered and as to which the irregularities have not been cured or waived, will be returned by the exchange agent to the tendering holder, unless otherwise provided in the letter of transmittal, promptly after the expiration of the exchange offer or termination of the exchange offer.

Except as otherwise provided in this prospectus, you may withdraw your tender of original bonds at any time prior to 5:00 p.m., New York City time, on the expiration date.

If certificates for original bonds have been delivered or otherwise identified to the exchange agent, then, prior to the release of such certificates, you must also submit:

If original bonds have been tendered pursuant to the procedures for book-entry transfer described above, any notice of withdrawal must specify the name and number of the account at the book-entry transfer facility to be credited with the withdrawn original bonds and otherwise comply with the procedures of the facility. We will determine all questions as to the validity, form and eligibility, including time of receipt of notices of withdrawal, and our determination will be final and binding on all parties. Any original bonds so withdrawn will be deemed not to have been validly tendered for exchange for purposes of the exchange offer. Any original bonds that have been tendered for exchange but that are not exchanged for any reason will be returned to their holder, without cost to the holder, or, in the case of book-entry transfer, the original bonds will be credited to an account at the book-entry transfer facility, promptly after withdrawal, rejection of tender or termination of the exchange offer. Properly withdrawn original bonds may be retendered by following the procedures described under "Procedures for Tendering Original Bonds" above at any time prior to the expiration of the exchange offer.

U.S. Bank National Association has been appointed as the exchange agent for the exchange offer. U.S. Bank National Association also acts as trustee under the indenture. You should direct all executed letters of transmittal and all questions and requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for notice of guaranteed delivery to the exchange agent addressed as follows:

If you deliver the letter of transmittal to an address other than the one set forth above or transmit instructions via facsimile to a number other than the one set forth above, that delivery or those instructions will not be effective.

The registration rights agreement provides that we will bear any and all expenses in connection with the performance of our obligations relating to the registration of the exchange bonds and the conduct of the exchange offer. These expenses include registration and filing fees, accounting and legal fees and printing costs, among others. We will pay the exchange agent reasonable and customary fees for its services and reasonable out-of-pocket expenses in connection with this exchange offer. We may also reimburse brokerage houses and other custodians, nominees and fiduciaries for customary mailing

and handling expenses incurred by them in forwarding this prospectus and related documents to their clients that are holders of the original bonds and for handling or tendering for such clients.

We have not retained any dealer-manager in connection with the exchange offer and will not pay any fee or commission to any broker, dealer, nominee or other person, other than the exchange agent, for soliciting tenders of original bonds pursuant to the exchange offer.

We will record the exchange bonds in our accounting records at the same carrying value as the original bonds which is the aggregate principal amount as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes upon the consummation of the exchange offer. The expenses of the exchange offer will be amortized over the term of the exchange bonds.

We will not pay transfer taxes, if any, applicable to the exchange of original bonds under the exchange offer. Holders who tender their original bonds for exchange will not be required to pay any transfer taxes. However, holders who instruct us to register exchange bonds in the name of, or request that original bonds not tendered or not accepted in the exchange offer be returned to, a person other than the registered tendering holder will be required to pay any applicable transfer tax. If satisfactory evidence of payment of such taxes is not submitted with the letter of transmittal, the amount of such transfer taxes will be billed to that tendering holder.

If you do not exchange your original bonds for exchange bonds under the exchange offer, your original bonds will remain subject to the restrictions on transfer of such original bonds:

In general, you may not offer or sell your original bonds unless they are registered under the Securities Act or if the offer or sale is exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the original bonds under the Securities Act.

Participating in the exchange offer is voluntary, and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your decision on what action to take.

We may in the future seek to acquire untendered original bonds in open market or privately negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any original bonds that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered original bonds.

The exchange bonds will be issued pursuant to the same indenture as the original bonds. The terms of the exchange bonds to be issued in the exchange offer are substantially identical to the original bonds, except that the exchange bonds will be registered under the Securities Act, and do not have any transfer restrictions, registration rights or additional interest provisions. The exchange bonds will mature on March 15, 2019. We will pay interest on the bonds at the annual rate of 6.10% (on the basis of a 360-day year of twelve 30-day months), from the date of issuance or from the most recent interest payment date to which interest has been paid or provided for, payable semi-annually on March 15 and September 15 of each year. The first interest payment date will be September 15, 2009. Interest on the exchange bonds will accrue from the last date on which interest was paid on the original bonds or, if no interest has been paid, from the issue date of the original bonds. On each interest payment date, we will pay interest to the person in whose name the exchange bonds are registered at 5:00 P.M. New York City time on the regular record date for that interest payment, which is the 1st day (whether or not a business day) of the calendar month of such interest payment date. If interest on the exchange bonds is not punctually paid or duly provided for, we will pay that amount instead to each registered holder of the exchange bonds on a special record date not more than 15 nor less than 10 days prior to the date of the proposed payment. Principal of, and premium (if any) and interest on, the exchange bonds will be payable, and the transfer of interests in the exchange bonds will be effected, through the facilities of DTC, as described below under "Book-Entry." The exchange bonds will be issued in $1,000 denominations or any integral multiple of $1,000.

The exchange bonds will be registered in the name of Cede & Co., as nominee of DTC, pursuant to DTC's Book-Entry-Only System. Purchases of beneficial interests in the exchange bonds will be made in book-entry form, without certificates. If at any time the Book-Entry-Only System is discontinued for the exchange bonds, the exchange bonds will be exchangeable for other fully registered certificated exchange bonds of like tenor and of an equal aggregate principal amount, in authorized denominations. See "Book-Entry." The trustee may impose a charge sufficient to reimburse us or the trustee for any tax, fee or other governmental charge required to be paid with respect to such exchange or any transfer of a exchange bond. The cost to us or the trustee, if any, of preparing each new exchange bond issued upon such exchange or transfer, and any other expenses incurred by us or the trustee in connection therewith, will be paid by the person requesting such exchange or transfer.

The exchange bonds will be secured equally and ratably under the indenture by a lien on substantially all our owned tangible and certain of our intangible assets. See "SUMMARY OF THE INDENTURE" for a further explanation.

Interest on the exchange bonds will be payable by check mailed to the registered owners thereof. However, interest on the exchange bonds will be paid to any holder of $1,000,000 or more in aggregate principal amount of exchange bonds by wire transfer to a wire transfer address within the continental United States upon the written request of such holder received by the trustee not less than five days prior to the record date. As long as the exchange bonds are registered in the name of Cede & Co., as nominee of DTC, such payments will be made directly to DTC. See "Book-Entry."

We may redeem the exchange bonds, in whole or in part, on any date prior to their maturity, at our option. We must give at least 30 days', but not more than 60 days', prior notice of redemption mailed to the registered address of each holder of exchange bonds being redeemed except as otherwise

required by the procedures of DTC. The redemption price for the exchange bonds will be equal to the greater of:

If there is no U.S. Treasury security having a life equal to the remaining average life of the exchange bonds being redeemed, the discount rate will be calculated using a yield to maturity determined on a straight-line basis (rounding to the nearest calendar month, if necessary) from the average yield to maturity of two U.S. Treasury securities having lives most closely corresponding to the remaining average life of the exchange bonds being redeemed and trading in the secondary market at the price closest to par.

If less than all of the outstanding exchange bonds are to be redeemed, the exchange bonds to be redeemed will be selected by the trustee in any method it deems fair and appropriate, and the portion of the exchange bonds not so redeemed will be in a minimum amount of $1,000.

If we give notice of the optional redemption of the exchange bonds but the trustee does not have enough funds on deposit to pay the full redemption price of the exchange bonds to be redeemed, those exchange bonds will remain outstanding as though no redemption notice had been given. The failure of the trustee to have sufficient funds to effect the redemption will not constitute a payment or other default by us under the indenture and we will not be liable to any holder of those exchange bonds as a result of the failed redemption. If the trustee has enough funds on deposit to effect a redemption at the time we give notice of the redemption, then we are obligated to redeem the exchange bonds as provided in that notice.

The certificates representing the exchange bonds will be issued in fully registered form, without interest coupons. The exchange bonds will be deposited with, or on behalf of, DTC, and registered in the name of Cede & Co., as DTC's nominee in the form of one or more global certificates. Upon the issuance of the global certificates, DTC or its nominee will credit, on its internal system, the respective principal amount of the individual beneficial interests represented by such global certificates to the accounts of persons who have accounts with such depositary. Ownership of beneficial interests in a global certificate will be limited to persons who have accounts with DTC (participants) or persons who hold interests through participants. Ownership of beneficial interests in a global certificate will be shown on, and the transfer of that ownership will be effected only through, records maintained by DTC or its nominee (with respect to interests of participants) and the records of participants (with respect to interests of persons other than participants).

Investors that exchange original bonds for exchange bonds may also hold their interests directly through Clearstream Banking or Euroclear, if they are participants in such systems, or indirectly through organizations that are participants in such systems. Investors may also hold such interests through organizations other than Clearstream Banking or Euroclear that are participants in the DTC system. Clearstream Banking and Euroclear will hold interests in the global certificate representing exchange bonds on behalf of their participants through DTC.

So long as DTC, or its nominee, is the registered owner or holder of a global certificate, DTC or such nominee, as the case may be, will be considered the sole owner or holder of the exchange bonds represented by such global certificate for all purposes under the indenture. No beneficial owner of an interest in a global certificate will be able to transfer the interest except in accordance with DTC's applicable procedures, in addition to those provided for under the indenture and, if applicable, those of Euroclear and Clearstream Banking.

Payments of the principal of and interest on a global certificate will be made to DTC or its nominee, as the case may be, as the registered owner of the global certificate. Neither us, the trustee nor any paying agent will have any responsibility or liability for any aspect of the records relating to or payments made on account of beneficial ownership interests in a global certificate or for maintaining, supervising or reviewing any records relating to such beneficial ownership interests. DTC or its nominee, upon receipt of any payment of principal or interest in respect of a global certificate, will credit participants' accounts with payments in amounts proportionate to their respective beneficial interests in the principal amount of such global certificate as shown on the records of DTC or its nominee. We also expect that payments by participants to owners of beneficial interests in such global certificate held through such participants will be governed by standing instructions and customary practices, as is now the case with securities held for the accounts of customers registered in the names of nominees for such customers. Such payments will be the responsibility of such participants.

Transfers between participants in DTC will be effected in the ordinary way in accordance with DTC rules. If a holder requires physical delivery of a certificated exchange bond for any reason, including to sell exchange bonds to persons in jurisdictions which require such delivery of such exchange bonds or to pledge such exchange bonds, the holder must transfer its interest in a global certificate in accordance with DTC's applicable procedures and the procedures set forth in the indenture and, if applicable, those of Euroclear and Clearstream Banking. Because DTC can act only on behalf of participants in DTC, which in turn act on behalf of indirect participants, the ability of a person having beneficial interests in a global certificate to pledge such interests to persons that do not participate in the DTC system, or otherwise take actions in respect of such interests, may be affected by the lack of a physical certificate evidencing such interests.

DTC will take any action permitted to be taken by a holder of exchange bonds (including the presentation of exchange bonds for exchange as described below) only at the direction of one or more participants to whose account the DTC interests in a global certificate is credited and only in respect of such portion of the aggregate principal amount of the exchange bonds as to which such participant or participants has or have given such direction. However, if there is an event of default under the exchange bonds, DTC will exchange a global certificate for certificated exchange bonds, which it will distribute to its participants.

DTC is a limited purpose trust company organized under the laws of the State of New York, a "banking organization" within the meaning of New York Banking Law, a member of the Federal Reserve System, a "clearing corporation" within the meaning of the Uniform Commercial Code and a "Clearing Agency" registered pursuant to the provisions of Section 17A of the Exchange Act. DTC was created to hold securities for its participants and facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes in accounts of its participants, thereby eliminating the need for physical movement of certificates. Participants include securities brokers and dealers, banks, trust companies and clearing corporations and may include certain other organizations. Indirect access to the DTC system is available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly (indirect participants). The rules applicable to DTC and its participants are on file with the SEC.

Although DTC, Euroclear and Clearstream Banking are expected to follow the foregoing procedures in order to facilitate transfers of interests in the exchange bonds represented by global certificates among their respective participants, they are under no obligation to perform or continue to perform such procedures, and such procedures may be discontinued at any time. Neither we nor the trustee will have any responsibility for the performance by DTC, Euroclear or Clearstream Banking or their respective participants or indirect participants of their respective obligations under the rules and procedures governing their operations.

If DTC is at any time unwilling or unable to continue as a depositary for a global certificate and a successor depositary is not appointed, we will issue certificated exchange bonds in exchange for a global certificate.

We will make all payments of principal and interest in immediately available funds.

Secondary trading in long-term bonds and notes of corporate issuers is generally settled in clearing-house or next-day funds. In contrast, beneficial interests in the exchange bonds that are not certificated exchange bonds will trade in DTC's Same-Day Funds Settlement System until maturity. Therefore, the secondary market trading activity in such interests will settle in immediately available funds. No assurance can be given as to the effect, if any, of settlement in immediately available funds on trading activity in the exchange bonds.

The information in this subsection, "Book-Entry," concerning DTC and DTC's book-entry system has been obtained from sources that we believe to be reliable, but we do not take any responsibility for the accuracy of this information.

The exchange bonds will be secured equally and ratably under the indenture by a lien on substantially all of our tangible and some of our intangible assets, including those we acquire in the future. The mortgaged assets include our electric generating plants and some of our contracts for the purchase, sale or transmission of electricity or pooling or other power supply arrangements of more than one year in duration or that relate to the ownership, operation, construction or maintenance of our electric generation facilities, but excluding all excepted property and excludable property described below.

The indenture does not include in the mortgaged assets, among other things, the following excepted property:

The indenture also excludes from mortgaged property any property as to which we have delivered to the trustee prior to acquiring such property a certificate stating that such property is to be excluded from the lien of the indenture and that we would meet our rate covenant even if we do not have use of such property.

Our title to the mortgaged property and the lien of the indenture are subject to permitted exceptions and encumbrances, which include, among other things, identified exceptions and encumbrances existing in March 1997, as long as such matters do not materially impair the use of such property; non-delinquent or contested taxes; mechanics', materialmens' or contractors' liens; local improvement district assessments; leases for a term of not more than ten years or, if for a term of more than ten years, leases which would not materially impair our use of the leased property in the conduct of our business; specified easements; the undivided interests of other co-owners in our facilities and liens on our undivided interests in co-owned facilities, and rights of such owners in property owned jointly with us; the pledge of current assets (other than accounts receivable) to secure current liabilities; and liens which have been bonded for or for the payment of which a deposit had been made in the full amount of such lien; and other exceptions and encumbrances which we do not believe adversely affect

in any material respect our right to use our property to secure the exchange bonds. The lien of the indenture is also shared with the trustee under the indenture to secure and allow the trustee to recover amounts that may be owed to the trustee under the indenture.

All of our property acquired after the date hereof, other than excepted property and excludable property, is subject to the lien of the indenture, but subject to:

So long as no event of default exists under the indenture, we will be able to sell, exchange or otherwise dispose of any part of the mortgaged property to facilitate our day-to-day operations. In order to obtain a release of the mortgaged property being sold, exchanged or otherwise disposed of from the trustee, we must find that the release will not impair the security under the indenture and that the sale, exchange or other disposition is:

Some of these releases also require the substitution of bondable additions, the deposit of cash with the trustee (which would constitute trust moneys as described below), the retirement or defeasance of indenture obligations, or the deposit of designated qualifying securities with the trustee, in each case of equal value to the fair value of the property to be released. Cash deposited with the trustee as a result of the authentication and delivery of indenture obligations can be withdrawn against 90.91% of bondable additions, or retired or defeased indenture obligations of equal value or deposited designated qualifying securities of equal value. Trust moneys can be withdrawn against bondable additions, retired or defeased indenture obligations, or deposited designated qualifying securities, in each case of equal value, and can, at our option, be used for the redemption of indenture obligations prior to their maturity, for the payment of principal on indenture obligations at their maturity or for the purchase of indenture obligations. To the extent that any trust moneys consist of the proceeds of insurance upon any part of the trust estate, those trust moneys can be withdrawn to reimburse us for costs to repair, rebuild or replace the destroyed or damaged property.

The indenture requires us to establish and collect rates that produce money sufficient, together with other money available to us, to enable us to comply with all covenants under the indenture. Subject to any necessary approval or determination of any regulatory or judicial authority with jurisdiction over our rates, the indenture requires us to establish and collect rates for the use or the sale of the output, capacity or service of our properties which are reasonably expected, together with our other revenue, to yield a margins for interest ratio equal to at least 1.10 for each fiscal year. The margins for interest ratio is the ratio of margins for interest for any period to total interest charges for that period. Margins for interest means, for any period, the sum of each of the following for that period:

Interest charges means, for any period, our total interest charges (whether capitalized or expensed) for the period with respect to interest accruing on all outstanding indenture obligations and on all debt secured by a lien equal to or prior to the lien of the indenture, but excludes interest accruing in respect of some indenture obligations that were issued on the basis of designated qualifying securities or indenture obligations with regards for which Georgia Transmission has assumed the payment obligations.

Promptly upon any material change in the circumstances which were contemplated at the time the rates were most recently reviewed, but at least once every 12 months, we are required to review our rates and, subject to any necessary regulatory approval, promptly establish or revise our rates as necessary to comply with the foregoing requirements. A failure by us to actually achieve a 1.10 margins for interest ratio will not itself constitute an event of default under the indenture. However, a failure to establish rates reasonably expected to achieve a 1.10 margins for interest ratio will be an event of default if the failure continues for 45 days after we receive notice thereof, unless the failure results from our inability to obtain regulatory approval. To enhance financial coverage during an anticipated period of generation facility construction, our board of directors approved a budget for 2009 to achieve a 1.12 margins for interest ratio, above the minimum 1.10 ratio required by the indenture. Our board of directors will evaluate coverage ratios throughout the period of anticipated construction and may choose to increase or decrease the margins for interest ratio in the future.

The indenture prohibits us from making any distribution, payment or retirement of patronage capital to our members if, at the time thereof or after giving effect thereto:

The indenture obligates us to keep all of the mortgaged property free and clear of other liens, subject to permitted exceptions and purchase money or pre-existing liens on our after-acquired property not in excess of 80% (or with respect to property that is not necessary to the operations of the remaining portion of our system, 100%) of the lesser of the cost or the fair value of the property and in the aggregate not in excess of 15% of the aggregate principal amount of all indenture obligations.

The indenture requires us to invest or direct the trustee to invest at least 75% of each of (i) our cash on hand for working capital needs, (ii) trust moneys and (iii) cash deposited under the indenture, in:

In connection with any indenture obligation, we may obtain credit enhancement, through an insurance policy, letter of credit, financial guaranty insurance policy or other similar obligation to pay when due (to the extent not paid by us) the principal and interest on indenture obligations.

The aggregate principal amount of indenture obligations that may be issued under the indenture is not limited. Additional indenture obligations, ranking equally and ratably with the existing indenture obligations, may be issued from time to time:

Bondable additions equals (i) the bondable value of all property additions not previously certified as bondable additions, less (ii) property subject to the lien of the indenture that has been retired and not yet counted in the calculation of bondable additions, referred to as retirements. Property additions are limited under the indenture to certain of our property that is chargeable to our fixed plant accounts, subject to the lien of the indenture, acquired or constructed by us since March 1, 1997, and not subject to pre-existing liens securing indebtedness prior to or on a parity with the lien of the indenture. For the purpose of calculating the amount of property additions and retirements, the bondable value of property acquired after March 1, 1997 is the lesser of its cost or fair value to us (determined as of the time of acquisition), and the bondable value of property acquired on or before March 1, 1997 is the net book value of such property as of March 1, 1997. The amount of bondable additions available for the issuance of additional indenture obligations as of March 31, 2009 was approximately $152 million and the amount of retired or defeased indenture obligations not previously used as the basis for issuing additional indenture obligations was approximately $588 million.

Designated qualifying securities are securities, including bonds or other debt instruments, held by the trustee and issued by one of our subsidiaries subject to an indenture, mortgage or other security instrument substantially identical in substance to the provisions of our indenture (subject to limited exceptions), which securities we have designated as (i) the basis for additional indenture obligations, (ii) the withdrawal of specified assets held by the trustee, or (iii) the release of mortgaged property. The aggregate amount of designated qualifying securities that can be deposited with the trustee at any one time cannot exceed 20% of the aggregate principal amount of indenture obligations then outstanding.

We may also use certified progress payments (as described below) as the basis for the issuance of additional indenture obligations in order to finance the construction of generation and related facilities. Certified progress payments are payments we make pursuant to a qualified EPC contract, which payments we are certifying as the basis for the issuance of additional indenture obligations. These are amounts that we would assign to our fixed plant accounts and that will constitute property additions upon the performance of the qualified EPC contract. A qualified EPC contract is any contract providing for the engineering, procurement or construction of generation or related facilities that we intend to own upon performance of the qualified EPC contract, and the payments for which are used as the basis for the issuance of additional indenture obligations. We can issue additional indenture obligations up to 80% of the amount of the certified progress payments. The total amount of indenture

obligations outstanding at any time on the basis of certified progress payments may not exceed 40% of the total obligations then outstanding under the indenture. Upon performance of the qualified EPC contract, we may convert the amounts outstanding under the indenture obligations that were issued on the basis of certified progress payments to amounts outstanding under indenture obligations issued on the basis of bondable additions.

Before we may issue additional indenture obligations on the basis of bondable additions, retirements or defeasance of indenture obligations, the deposit of cash with the trustee, the deposit of designated qualifying securities with the trustee, or certified progress payments, we must certify that our margins for interest ratio was at least 1.10 during the immediately preceding fiscal year or during any consecutive 12-month period within the 18-month period immediately preceding our request for additional obligations.

Subject to the provisions of the indenture relating to the duties of the trustee, if an event of default occurs and is continuing, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request or direction of any of the holders, unless those holders (other than the United States of America or its agencies or instrumentalities) have offered to the trustee reasonable indemnity. Subject to provisions for the indemnification of the trustee, the holders of a majority in aggregate principal amount of the outstanding indenture obligations will have the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or exercising any trust or power conferred on the trustee, except that, so long as it is not in default with respect to its credit enhancement for any indenture obligations, a credit enhancer for, and not the actual holders of, those indenture obligations would be deemed to be the holder of those indenture obligations for purposes of, among other things, taking action in connection with the remedies set forth in the indenture.

If an event of default occurs and is continuing, either the trustee or the holders of at least 25% in aggregate principal amount of the outstanding indenture obligations may accelerate the maturity of all indenture obligations. However, after the acceleration, but before a sale of any of the trust estate or a judgment or decree based on acceleration, the holders of a majority in aggregate principal amount of

outstanding indenture obligations may, under certain circumstances, rescind the acceleration if all events of default, other than the non-payment of accelerated principal, have been cured or waived as provided in the indenture.

No holder of any indenture obligation has any right to institute any proceeding with respect to the indenture or for any remedy thereunder, unless:

However, the limitations on the holders' rights to institute proceedings do not apply to a suit instituted by a holder of an indenture obligation for the enforcement of payment of the principal of and premium, if any, or interest on the indenture obligation on or after the respective due dates stated therein.

The indenture provides that the trustee, within 90 days after the occurrence of the event of default (but at least 60 days after the occurrence of some specified events of default), will give to the holders of indenture obligations notice of all uncured defaults known to it, provided that, except that in the case of a default in the payment of principal of, and premium, if any, or interest on any indenture obligations, the trustee will be protected in withholding that notice if it in good faith determines that the withholding of that notice is in the interest of the holders of the indenture obligations.

If an event of default occurs and is continuing, the trustee may sell the mortgaged property, in either judicial or nonjudicial proceedings. The proceeds from disposition of the mortgaged property will be applied as follows:

The indenture requires us to deliver to the trustee, within 120 days after the end of each calendar year, a written statement as to our compliance (determined without regard to any grace period or notice requirement) with all of our obligations under the indenture. In addition, we are required to deliver to the trustee, promptly after any of our officers may be reasonably deemed to have knowledge

of a default under the indenture, a written notice specifying the nature and duration of the default and the action we are taking and propose to take with respect to the default.

Our compliance with the covenants contained in the indenture relating to (i) limitation on liens, (ii) payment of taxes, (iii) maintenance of properties, (iv) insurance, (v) delivery of annual compliance certificates and notices of default under the indenture, (vi) establishing and reviewing certain rates, (vii) distributions to our members and (viii) investment of certain moneys, may be waived by a vote of the holders of a majority of the aggregate principal amount of the outstanding indenture obligations.

Without the consent of the holders of any indenture obligations, we and the trustee may, from time to time, enter into one or more supplemental indentures:

A supplemental indenture will be presumed not to materially and adversely affect the rights of holders if (i) the indenture, as supplemented and amended, secures equally and ratably the payment of principal of (and premium, if any) and interest on the indenture obligations which are to remain outstanding and (ii) we furnish to the trustee written evidence from at least two nationally recognized statistical rating organizations then rating the indenture obligations (or other obligations primarily secured by indenture obligations) that their respective ratings of the indenture obligations (or other obligations primarily secured by indenture obligations) will not be withdrawn or reduced as a result of the changes in the indenture effected by the supplemental indenture, provided that any changes in the indenture that require the consent of all of the holders of indenture obligations affected thereby may not be made on the basis that they do not materially and adversely affect the rights of holders.

With the consent of the holders of not less than a majority in principal amount of the indenture obligations of all series then outstanding affected by the supplemental indenture, we and the trustee may, from time to time, enter into one or more supplemental indentures to add, change or eliminate any of the provisions of the indenture or modify the rights of the holders of the indenture obligations. However, no supplemental indenture will, without the consent of the holder of each outstanding indenture obligation affected thereby:

Under the indenture, any credit enhancer that agrees to provide any undertaking to pay amounts due with respect to any indenture obligations to the extent those amounts are not paid by us, for example an insurer of our indenture obligations, will be considered a holder of those indenture obligations for the purpose of (i) giving any requisite approval or consent to supplemental indentures or amendments to the indenture (other than those amendments which require the consent of the holders of each indenture obligation affected thereby) and (ii) giving any other approval or consent,

giving any notice, effecting any waiver or authorization, exercising any remedies or taking any other action that can be taken by the holder of those indenture obligations. However, if the credit enhancer is in default with respect to the performance of its undertaking, it will not be considered a holder in place of the holders of those indenture obligations.

With respect to indenture obligations guaranteed or insured by the United States of America, acting by and through the Administrator of the Rural Utilities Service, the Rural Utilities Service, rather than the actual payee of the indenture obligations, will have all of the rights of a holder of the indenture obligations for the period in which those indenture obligations are guaranteed or insured by the United States of America, acting by and through the Administrator of the Rural Utilities Service, regardless of whether the Rural Utilities Service actually possesses those indenture obligations. All the applicable indenture obligations must be registered to show the United States of America, acting by and through the Administrator of the Rural Utilities Service, as the registered holder of the indenture obligations, unless the Rural Utilities Service otherwise requests.

Subject to some conditions, the indenture provides that indenture obligations of any series, or any maturity within a series, will be deemed to have been paid and our obligations to the holders of those indenture obligations will be discharged (subject to receipt of required rulings or opinions relating to tax matters), if we deposit with the trustee or paying agent cash or defeasance securities maturing as to principal and interest in such amounts and at such times as are sufficient, without consideration of reinvestment of such interest, to pay when due the principal or (if applicable) redemption price and interest due and to become due on those indenture obligations. Defeasance securities include non-callable bonds or other obligations, the principal and interest on which constitute direct obligations of, or are unconditionally guaranteed by, the United States of America, or certificates of interest or participation in any of these obligations, or in specified portions of these obligations (which may consist of specified portions of the interest on the certificates).

We are subject to federal and state corporate income taxation but, as a cooperative, we are allowed a deduction for patronage sourced margins that we allocate to our members. We are, however, liable for federal and state income taxes on that portion of our taxable income which is not derived from patronage sources, and we are entitled to no special deduction with respect to our non-patronage sourced taxable income. Due to the availability of the special deduction for patronage sourced margins that we allocate to our members, we do not anticipate that the amount of our federal and state corporate income taxes will be material in the foreseeable future. See Note 3 to Notes to Audited Consolidated Financial Statements for a discussion of our net operating loss carryforwards.

Like any corporation, the relevant taxing authorities may challenge how we treat certain items on our tax returns. Because we are a cooperative, these authorities may also challenge our classification of items of income and expense between patronage and non-patronage sources. If, in any year, the relevant authorities were to reclassify any of our patronage sourced income as non-patronage sourced, or any of our non-patronage sourced expenses as patronage sourced, it is possible that we might owe income taxes in that year and the amount of those income taxes might be material.

The exchange of the original bonds for exchange bonds pursuant to the exchange offer should not be treated as a taxable event for United States federal income tax purposes because the exchange bonds will not differ materially in kind or exchange from the original bonds, with the result that the holding period for your exchange bonds will include the holding period of the original bonds you surrender in exchange therefor, and the basis of your exchange bonds will be the same as the basis of

the original bonds you surrender in exchange (as determined immediately prior to the date of exchange).

In any event, persons considering the exchange of original bonds for exchange bonds should consult their own tax advisors concerning the United States federal income tax consequences in light of their particular situations as well as any consequences arising under the laws of any other taxing jurisdiction.

The following is a summary of the material United States federal income tax consequences relating to the ownership and disposition of the exchange bonds by an initial beneficial holder of the bonds who purchased the original bonds for cash at the original offering price, exchanges its original bonds for exchange bonds pursuant to the exchange offer, and who holds the bonds as capital assets within the meaning of section 1221 of the Internal Revenue Code of 1986. This discussion is based upon the Code, existing and proposed United States Treasury Regulations and judicial decisions and administrative interpretations thereof, all as of the date of this prospectus and all of which are subject to change, possibly with retroactive effect, or to different interpretations. We cannot assure you that the IRS will not challenge one or more of the tax consequences described in this section. We have not obtained, nor do we intend to obtain, a ruling from the IRS or an opinion of counsel with respect to the United States federal tax consequences of purchasing, owning or disposing of the bonds.

This discussion does not address all United States federal tax considerations that may be relevant to a particular holder in light of the holder's circumstances or to certain categories of investors that may be subject to special rules, such as financial institutions, regulated investment companies, insurance companies, tax-exempt organizations, dealers in securities, persons who hold the bonds through partnerships or other pass-through entities, United States expatriates or persons who hold the bonds as part of a hedge, conversion transaction, straddle or other integrated transaction. This discussion also does not address United States federal estate or gift tax consequences, the tax considerations arising under the laws of any state, local or foreign jurisdiction or under any applicable tax treaties or alternative minimum tax issues.

This discussion is for general purposes only. You should consult your own tax advisor as to the particular tax consequences to you of the exchange, ownership and disposition of the bonds, including the effect and applicability of state, local or foreign tax laws or tax treaties and the possible effects of changes in the tax law.

This prospectus is not intended or written to be used, and it cannot be used, by any purchaser for the purpose of avoiding penalties that may be imposed under the Code. This prospectus was written, in part, to support the promotion and marketing of the bonds. Each potential investor should seek advice based on the investor's particular circumstances from an independent tax advisor.

As used in this section, the term U.S. holder means a beneficial owner of a bond that is:

As used in this section, the term non-U.S. holder means any owner (or beneficial owner) of a bond that is not a U.S. holder, other than a partnership.

If a partnership holds bonds, the tax treatment of a partner will generally depend upon the status of the partner and upon the activities of the partnership. Partnerships and partners of partnerships holding bonds should consult their own tax advisors regarding the tax consequences associated with an investment in, and exchange, ownership and disposition of, the bonds (including their status as U.S. holders or non-U.S. holders).

Generally, you will be taxed on interest on the bonds at the time it accrues or is received, depending on your method of tax accounting.

Upon a sale, exchange (other than in connection with the exchange offer) or redemption of a bond, you will generally recognize gain or loss equal to the difference between the amount realized on the sale (not including any amounts attributable to accrued and unpaid interest) and your adjusted basis in the bond. Except to the extent attributable to accrued but unpaid interest, any gain or loss you recognize on the sale of a bond should generally be capital gain or loss.

If you are a non-U.S. holder, interest paid to you in respect of the bonds should generally not be subject to United States federal income tax provided that:

Similarly, if you are a non-U.S. holder, gain recognized by you in connection with a sale, exchange or redemption of your bonds should generally not be subject to U.S. federal income tax provided that:

If you fail to satisfy the provisos set forth above, the interest you receive on the bonds and/or the gain you recognize on a sale or disposition of the bonds may be subject to U.S. income tax, and you

should consult your own tax advisor as to the U.S. federal income tax consequences applicable to your acquisition, ownership and disposition of the bonds.

Information reporting to the IRS may be required with respect to payments on your bonds and with respect to proceeds from the sale of the bonds to holders other than corporations and certain other exempt recipients. A "backup" withholding tax may also apply to those payments if you fail to provide certain identifying information (such as your taxpayer identification number or an attestation to your status as a non-U.S. holder). Backup withholding is not an additional tax and may be refunded (or credited against your U.S. federal income tax liability, if any) provided that certain required information is furnished to the IRS in a timely manner.

Each broker-dealer that receives exchange bonds for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such exchange bonds. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of exchange bonds received in exchange for original bonds where such original bonds were acquired as a result of market-making activities or other trading activities. We have agreed to keep effective the registration statement of which this prospectus is a part until the earlier of 180 days after the completion of the exchange offer or such time as broker-dealers no longer own any exchange bonds. In addition, all dealers effecting transactions in the exchange bonds may be required to deliver a prospectus.

We will not receive any proceeds from any sale of exchange bonds by broker-dealers. Exchange bonds received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the exchange bonds or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or at negotiated prices. Any such resale may be made directly to purchasers or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer and/or the purchasers of any such exchange bonds. Any broker-dealer that resells exchange bonds that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such exchange bonds may be deemed to be an "underwriter" within the meaning of the Securities Act, and any profit of any such resale of exchange bonds and any commission or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 180 days after the expiration date of the exchange offer (or until the broker-dealer no longer holds registrable securities), we will promptly send additional copies of this prospectus and any amendments or supplements to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. Subject to certain limitations set forth in the registration rights agreement, we have agreed to pay all expenses incident to the exchange offer other than commissions or concessions of any broker-dealer and will indemnify you (including any broker-dealers) against certain liabilities under the Securities Act.

The validity of the exchange bonds has been passed upon for us by Sutherland Asbill & Brennan LLP.

The financial statements as of December 31, 2008 and 2007 and for each of the three years in the period ended December 31, 2008 included in this Prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

We have filed with the SEC a registration statement on Form S-4 under the Securities Act with respect to the exchange bonds. This prospectus, which forms a part of the registration statement, does not contain all of the information set forth in the registration statement. For further information with respect to us and the exchange bonds, reference is made to the registration statement. Statements contained in this prospectus as to the contents of any contract or other document are not necessarily complete.

We have historically filed, on a voluntary basis, annual, quarterly and current reports and other information with the SEC pursuant. You may read and copy any document we have or will file with the SEC at the SEC public website (http://www.sec.gov) or at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Copies of such materials can be obtained from the Public Reference Room of the SEC at prescribed rates. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

You should rely only upon the information provided in this prospectus. We have not authorized anyone to provide you with different information. You should not assume that the information in this prospectus is accurate as of any date other than the date of this prospectus.


		Page
Unaudited Financial Statements for the Quarterly Periods Ended March 31, 2009 and 2008
Unaudited Condensed Balance Sheets As of March 31, 2009 and December 31, 2008		F-2
Unaudited Condensed Statements of Revenues and Expenses For the Three Months ended March 31, 2009 and 2008		F-4
Unaudited Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit For the Three Months ended March 31, 2009 and 2008		F-5
Unaudited Condensed Statements of Cash Flows For the Three Months ended March 31, 2009 and 2008		F-6
Notes to Unaudited Condensed Financial Statements For the Three Months ended March 31, 2009 and 2008		F-7
Audited Financial Statements for each of the three Fiscal Years Ended December 31, 2008
Consolidated Statements of Revenues and Expenses For the Years Ended December 31, 2008, 2007 and 2006		F-18
Consolidated Balance Sheets As of December 31, 2008 and 2007		F-19
Consolidated Statements of Capitalization As of December 31, 2008 and 2007		F-21
Consolidated Statements of Cash Flows For the Years Ended December 31, 2008, 2007 and 2006		F-22
Consolidated Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit For the Years Ended December 31, 2008, 2007 and 2006		F-23
Notes to Consolidated Financial Statements		F-24
Report of Independent Registered Public Accounting Firm		F-54

Oglethorpe Power Corporation

Condensed Balance Sheets (Unaudited)

March 31, 2009 and December 31, 2008

		2009			2008

		(dollars in thousands)
Assets
Electric plant:
	In service	$	5,923,360		$	5,906,865
	Less: Accumulated provision for depreciation		(2,787,009	)		(2,753,954	)

			3,136,351			3,152,911
	Nuclear fuel, at amortized cost		186,879			179,020
	Construction work in progress		373,384			307,464

			3,696,614			3,639,395

Investments and funds:
	Decommissioning fund		190,388			201,094
	Deposit on Rocky Mountain transactions		110,044			108,219
	Bond, reserve and construction funds		3,513			4,560
	Investment in associated companies		43,845			43,441
	Long-term investments		80,059			81,550
	Other, at cost		391			391

			428,240			439,255

Current assets:
	Cash and cash equivalents, at cost		414,101			167,659
	Restricted cash, at cost		—			10,255
	Restricted short-term investments		80,000			—
	Receivables		129,062			116,679
	Inventories, at average cost		184,651			175,350
	Prepayments and other current assets		4,031			5,619

			811,845			475,562

Deferred charges:
	Premium and loss on reacquired debt, being amortized		126,846			130,013
	Deferred amortization of capital leases		83,636			85,612
	Deferred debt expense, being amortized		44,785			41,905
	Deferred outage costs, being amortized		33,358			27,137
	Deferred tax assets		48,000			48,000
	Deferred asset associated with retirement obligations		76,841			60,310
	Deferred interest rate swap termination fees, being amortized		32,288			33,286
	Deferred depreciation expense		50,114			42,955
	Other		18,627			21,022

			514,495			490,240

		$	5,451,194		$	5,044,452

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

		2009			2008

		(dollars in thousands)
Equity and Liabilities
Capitalization:
	Patronage capital and membership fees	$	551,476		$	535,829
	Accumulated other comprehensive deficit		(1,173	)		(1,348	)

			550,303			534,481
	Long-term debt		3,656,911			3,278,856
	Obligation under capital leases		233,946			236,067
	Obligation under Rocky Mountain transactions		110,044			108,219

			4,551,204			4,157,623

Current liabilities:
	Long-term debt and capital leases due within one year		112,929			110,647
	Short-term borrowings		—			140,000
	Accounts payable		18,663			29,305
	Accrued interest		33,278			34,539
	Accrued and withheld taxes		6,997			18,827
	Members' advances, current		88,105			—
	Other current liabilities		42,925			28,081

			302,897			361,399

Deferred credits and other liabilities:
	Gain on sale of plant, being amortized		32,918			33,536
	Net benefit of Rocky Mountain transactions, being amortized		56,540			57,336
	Asset retirement obligations		286,024			281,458
	Accumulated retirement costs for other obligations		47,739			49,675
	Long-term contingent liability		48,000			48,000
	Members' advances		72,182			5,000
	Other		53,690			50,425

			597,093			525,430

		$	5,451,194		$	5,044,452

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

Oglethorpe Power Corporation

Condensed Statements of Revenues and Expenses (Unaudited)

For the Three Months Ended March 31, 2009 and 2008

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

Oglethorpe Power Corporation

Condensed Statements of Patronage Capital and Membership Fees
and Accumulated Other Comprehensive Deficit (Unaudited)

For the Three Months Ended March 31, 2009 and 2008

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

Oglethorpe Power Corporation

Condensed Statements of Cash Flows (Unaudited)

For the Three Months Ended March 31, 2009 and 2008

				2009			2008

				(dollars in thousands)
Cash flows provided (used) by operating activities:
	Net margin			$	15,647		$	6,667

	Adjustments to reconcile net margin to net cash provided (used) by operating activities:
		Depreciation and amortization, including nuclear fuel			54,405			52,034
		Accretion cost			4,565			4,303
		Amortization of deferred gains			(1,415	)		(1,415	)
		Allowance for equity funds used during construction			(795	)		(598	)
		Deferred outage costs			(13,850	)		(17,389	)
		Loss on sale of investments			4,792			2,428
		Regulatory deferral of costs associated with nuclear decommissioning			(7,747	)		(1,202	)
		Other			453			675
	Change in operating assets and liabilities:
		Receivables			4,589			(39,267	)
		Inventories			(9,300	)		326
		Prepayments and other current assets			1,588			1,551
		Accounts payable			(32,541	)		(7,152	)
		Accrued interest			(1,261	)		(672	)
		Accrued and withheld taxes			(11,830	)		(17	)
		Other current liabilities			(2,571	)		(11,425	)
		Settlement of interest rate swaps			—			(33,771	)
		Increase in Members' advances			155,287			—
			Total adjustments		144,369			(51,591	)

Net cash provided (used) by operating activities					160,016			(44,924	)

Cash flows provided (used) by investing activities:
	Property additions				(82,186	)		(89,006	)
	Activity in decommissioning fund—Purchases				(193,608	)		(118,133	)
	—Proceeds				192,686			112,776
	Activity in bond, reserve and construction funds—Purchases				(2	)		(35	)
	—Proceeds				1,049			1,077
	Decrease in restricted cash and cash equivalents				10,255			48,124
	Increase in restricted short-term investments				(80,000	)		(40,033	)
	Decrease (increase) in investment in associated organizations				(639	)		1,406
	Activity in other long-term investments—Purchases				(452	)		(172,111	)
	—Proceeds				—			178,395
	Other				2,011			2,448

Net cash provided (used) by investing activities					(150,886	)		(75,092	)

Cash flows provided (used) by financing activities:
	Long-term debt proceeds				408,900			—
	Long-term debt payments				(30,689	)		(67,063	)
	Payment of notes payable				(140,000	)		—
	Other				(899	)		298

Net cash provided (used) by financing activities					237,312			(66,765	)

Net decrease in cash and cash equivalents					246,442			(186,781	)
Cash and cash equivalents at beginning of period					167,659			290,930

Cash and cash equivalents at end of period				$	414,101		$	104,149

Supplemental cash flow information:
Cash paid for—
	Interest (net of amounts capitalized)			$	54,209		$	54,345
	Plant expenditures included in ending accounts payable			$	21,081		$	(10,602	)

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

Oglethorpe Power Corporation

Notes to Unaudited Condensed Financial Statements

March 31, 2009 and 2008

(A) General. The condensed financial statements included in this report have been prepared by Oglethorpe Power Corporation (Oglethorpe), pursuant to the rules and regulations of the Securities and Exchange Commission (SEC). In the opinion of management, the information furnished in this report reflects all adjustments (which include only normal recurring adjustments) and estimates necessary to fairly state, in all material respects, the results for the periods ended March 31, 2009 and 2008. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles (GAAP) have been condensed or omitted pursuant to SEC rules and regulations, although Oglethorpe believes that the disclosures are adequate to make the information presented not misleading. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in Oglethorpe's Audited Consolidated Financial Statements. The results of operations for the three-month period ended March 31, 2009 are not necessarily indicative of results to be expected for the full year. As noted in this prospectus, substantially all of Oglethorpe's sales are to its 38 electric distribution cooperative members (the Members) and, thus, the receivables on the accompanying balance sheets are principally from its Members. (See Notes to Audited Consolidated Financial Statements.)

(B) Fair Value Measurements. Fair value measurements for financial and non-financial assets and liabilities are disclosed in accordance with Statement of Financial Accounting Standards (SFAS) No. 157, "Fair Value Measurements." SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements.

SFAS No. 157 establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

As required by SFAS No. 157, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

The tables below details assets and liabilities measured at fair value on a recurring basis for the periods ending March 31, 2009 and December 31, 2008, respectively (dollars in thousands).

The following tables present assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs for the three months ended March 31, 2009 (dollars in thousands).

Based on market conditions including the failure of various auctions for auction rate securities in which Oglethorpe invested, Oglethorpe uses an income approach valuation using a discounted cash flow model based on projected cash flows at current rates and adjusted for illiquidity premiums based on discussions with market participants to determine the fair value of these investments. At March 31, 2009, Oglethorpe held auction rate securities with maturity dates ranging from March 15, 2028 to December 1, 2045.

Based on the fair value of these auction rate securities as of March 31, 2009 determined using a discounted cash flow analysis, an additional temporary impairment of approximately $24,000 was recorded as an incremental adjustment to the $1,657,000 that was previously recorded at December 31,

2008. The temporary impairment is reflected in "Accumulated Other Comprehensive Deficit" on the condensed unaudited balance sheets. The various assumptions Oglethorpe utilizes to determine the fair value of its auction rate securities investments will vary from period to period based on the prevailing economic conditions. If the market for Oglethorpe's auction rate securities investments continues to deteriorate, Oglethorpe may need to increase the illiquidity premium used in preparing a discounted cash flow model for these securities. A 25 basis point increase in the illiquidity premium used to determine the fair value of these investments at March 31, 2009, would have resulted in a decrease in the fair value of Oglethorpe's auction rate securities investments by approximately $1,540,000.

These investments were rated either A3 or Aaa by Moody's Investors Service ("Moody's") and AAA by Standard and Poor's ("S&P"), respectively, as of March 31, 2009. Therefore, it is expected that the investments will not be settled at a price less than par value. Because Oglethorpe has the ability and intent to hold these investments until a recovery of its original investment value, it considered the investments to be temporarily impaired at March 31, 2009.

(C) Adoption of SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities." Effective January 1, 2009, Oglethorpe adopted SFAS No. 161. The standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures that reflect the effect of these activities on an entity's financial position, financial performance, and cash flows.

Oglethorpe has entered into natural gas swap arrangements to manage its exposure to fluctuations in the market price of natural gas. Under these swap arrangements, 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.

At March 31 2009, the estimated fair value of Oglethorpe's natural gas contracts was an unrealized loss of approximately $35,432,000. See Note B for further discussion on fair value measurements of financial instruments. Consistent with Oglethorpe's rate-making for energy costs which are flowed-through to the Members, these unrealized losses are reflected as an unbilled receivable on Oglethorpe's balance sheet.

The following table presents Oglethorpe's natural gas derivative volumes, as of March 31, 2009, that are expected to settle each year:

The table below reflects the fair value of derivative instruments and their effect on Oglethorpe's condensed unaudited balance sheets for the period ending March 31, 2009 (dollars in thousands).

Effect of Derivative Instruments on the Condensed Statement of Revenues and Expenses

Oglethorpe is exposed to credit risk as a result of entering into these hedging arrangements. Credit risk is the potential loss resulting from a counterparty's nonperformance under an agreement. Oglethorpe manages credit risk with policies and procedures for, among other things, counterparty analysis, exposure measurement, and exposure monitoring and mitigation.

It is possible that volatility in commodity prices could cause the company to have credit risk exposures with one or more counterparties. If such counterparties fail to perform their obligations, the company could suffer a financial loss. However, as of March 31, 2009, all of the counterparties with transaction amounts outstanding in Oglethorpe's hedging portfolio are rated above investment grade by the major rating agencies or have provided a parental guaranty from one of their affiliates that is rated above investment grade.

Oglethorpe has entered into International Swaps and Derivatives Association Agreements with its natural gas hedge counterparties that mitigate credit exposure by creating contractual rights relating to creditworthiness, collateral and termination.

Additionally, Oglethorpe has implemented procedures to monitor the creditworthiness of our counterparties and to consider nonperformance in valuing counterparty positions. Oglethorpe has contracted with a third party to assist in monitoring counterparties' credit standing, including those that are experiencing financial problems, have significant swings in credit default swap rates, have credit rating changes by external rating agencies, or have changes in ownership. Net liability positions are

generally not adjusted as the company uses derivative transactions as hedges and has the ability and intent to perform under each of their contracts. In the instance of net asset positions, the company considers general market conditions and the observable financial health and outlook of specific counterparties, forward looking data such as credit default swaps, when available, and historical default probabilities from credit rating agencies in evaluating the potential impact of nonperformance risk to derivative positions.

The contractual agreements contain provisions that could require either Oglethorpe or the counterparty to post collateral or credit support. The amount of collateral or credit support that could be required is calculated as the difference between the aggregate fair value of the hedges and pre-established credit thresholds. The credit thresholds are contingent upon each party's credit standing and credit ratings from the major credit rating agencies (Moody's and S&P). The collateral and credit support requirements vary by contract and by counterparty. Oglethorpe may only post credit support in the form of a letter of credit due to provisions within its Indenture; however, Oglethorpe may receive collateral in the form of cash or credit support. As of March 31, 2009, neither Oglethorpe nor any counterparties were required to post credit support or collateral under any of these agreements. If the credit-risk-related contingent features underlying these agreements were triggered on March 31, 2009 due to Oglethorpe's credit rating being downgraded below investment grade, Oglethorpe could have been required to post letters of credit totaling up to $35,000,000 with its counterparties.

(D) Recently Issued or Adopted Accounting Pronouncements. In April 2009, the FASB issued Staff Position No. 157-4, "Determining Fair Value When the Volume and Level of Activity for the Asset or Liability Have Significantly Decreased and Identifying Transactions That Are Not Orderly" ("FSP 157-4"). FSP 157-4 emphasizes that even if there has been a significant decrease in the volume and level of activity for the asset or liability and regardless of the valuation technique and inputs used, the objective for the fair value measurement is unchanged from what it would be if markets were operating at normal activity levels or transactions were orderly; that is, to determine the current exit price. FSP 157-4 sets forth additional factors that should be considered to determine whether there has been a significant decrease in volume and level of activity when compared with normal market activity. The reporting entity shall evaluate the significance and relevance of the factors to determine whether, based on the weight of evidence, there has been a significant decrease in activity and volume. FSP 157-4 indicates that if an entity determines that either the volume or level of activity for an asset or liability has significantly decreased (from normal conditions for that asset or liability) or price quotations or observable inputs are not associated with orderly transactions, increased analysis and management judgment will be required to estimate fair value. FSP 157-4 further notes that a fair value measurement should include a risk adjustment to reflect the amount market participants would demand because of the risk (uncertainty) in the cash flows.

FSP 157-4 also requires a reporting entity to make additional disclosures in interim and annual periods. FSP 157-4 is effective for interim periods ending after June 15, 2009, with early application permitted for periods ending after March 15, 2009. Revisions resulting from a change in valuation techniques or their application are accounted for as a change in accounting estimate. Currently, the adoption of FSP 157-4 is not expected to have a material effect on Oglethorpe's results of operations, cash flows or financial condition.

In April 2009, the FASB issued FSP FAS 107-1 and APB 28-1, "Interim Disclosures about Fair Value of Financial Instruments" ("FSP FAS 107-1 and APB 28-1"). FSP FAS 107-1 and APB 28-1 require disclosures about fair value of financial instruments in interim and annual financial statements. FSP FAS 107-1 and APB 28-1 are effective for periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. Currently, the adoption of FSP 107-1 and APB 28-1 are not expected to have a material effect on Oglethorpe's results of operations, cash flows or financial condition.

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

In November 2007, the FASB issued a one-year deferral for the implementation of SFAS No. 157 "Fair Value Measurements" for non-financial assets and non-financial liabilities that are recognized or disclosed at fair value in the financial statements on a nonrecurring basis. The deferral was applicable for asset retirement obligations measured at fair value upon initial recognition under FASB Statement No. 143 "Accounting for Asset Retirement Obligations", or upon a remeasurement event. Oglethorpe adopted SFAS No. 157 for non-financial assets and non-financial liabilities effective January 1, 2009 with no material effect on its results of operations, cash flows or financial condition.

(E) Accumulated Comprehensive Deficit. The table below provides detail of the beginning and ending balance for each classification of accumulated other comprehensive deficit along with the amount of any reclassification adjustments included in margin for each of the periods presented in the Condensed Statements of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit. There were no material changes in the nature, timing or amounts of expected (gain) loss reclassified to net margin from the amounts disclosed in Oglethorpe's Audited Consolidated Financial Statements included herein.

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

(F) 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.

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

In general, environmental requirements are becoming increasingly stringent. New requirements may substantially increase the cost of electric service by requiring changes in the design or operation of existing facilities or changes or delays in the location, design, construction or operation of new facilities. Failure to comply with these requirements could result in the imposition of civil and criminal penalties as well as the complete shutdown of individual generating units not in compliance. Certain of Oglethorpe's debt instruments require us to comply in all material respects with laws, rules, regulations and orders imposed by applicable governmental authorities, which include current or future environmental laws and regulations. Should we fail to be in compliance with these requirements, it would constitute a default under such debt instruments. Although it is Oglethorpe's intent to comply with current and future regulations, Oglethorpe cannot provide assurance that it will always be in compliance with current and future regulations applicable to it.

(G) Pollution Control Revenue Bonds (PCBs). Since the second half of 2007, the three major credit rating agencies have had an on-going review of the monoline bond insurers primarily as a result of the exposure some insurers have to financial guarantees and credit default swaps related to structured finance obligations, primarily those backed by subprime residential mortgages. By mid-2008, many monoline bond insurers had been downgraded below their historical triple-A rating levels or had negative outlooks assigned to their triple-A ratings, including the insurers that provided guarantees on a significant portion of Oglethorpe's variable rate PCB indebtedness.

These bond insurer downgrades caused a corresponding downgrade of the ratings on the insured bonds, leading to increased focus on the underlying issuer credit, wider credit spreads and higher interest rates, and in some cases failed auctions in the auction rate securities (ARS) market and failed remarketings in the variable rate demand bond (VRDB) market. However, the bank liquidity support that is typically used in the VRDB market may somewhat mitigate the otherwise negative effect of bond insurer downgrades versus the ARS market which relies on the broker/dealers for liquidity support. The ARS market is no longer functioning as originally anticipated, and investors are trying to liquidate ARS investments as they can.

The bond insurer downgrades and related issues in the ARS market required Oglethorpe to refinance, or otherwise convert to a term or fixed rate of interest, approximately $819,000,000 of variable rate PCBs in 2008 (of which Georgia Transmission Corporation (GTC) has assumed an $86,000,000 obligation).

At March 31, 2009, Oglethorpe had $123,000,000 of PCBs in the ARS mode that remained outstanding. These ARS reprice in Dutch auctions that occur every 35 days, but the auctions have been failing consistently since early 2008 for the reasons described above. However, since the interest rates on these ARS, in the event of a failed auction, are reset at a percentage of LIBOR (which has been low in recent months), the interest rates on the ARS have been below 1% since January 2009.

(H) Restricted short-term investments. At March 31, 2009, Oglethorpe had $80,000,000 on deposit with RUS in the Cushion of Credit Account. The funds are restricted for future Rural Utilities Service (RUS)/Federal Financing Bank (FFB) debt service payments and earn interest at a RUS guaranteed rate of 5% per annum.

(I) Members' Advances. In December 2008, Oglethorpe instituted a power bill prepayment program pursuant to which Members can prepay their power bills from Oglethorpe at a discount for an agreed number of months in advance, after which point the funds are credited against the participating Members' monthly power bills. At March 31, 2009, Member advances including unpaid discounts were $160,287,000, of which, $88,105,000 is classified as current liabilities and $72,182,000 as deferred credits and other liabilities in the condensed balance sheets. In addition, Oglethorpe has received an additional $25,500,000 from Members in relation to this program, subsequent to March 31, 2009. These amounts will be applied against Members' power bills beginning in May 2009 and extending through June 2011.

Relationship with AIG Matched Funding Corp. Oglethorpe's wholly owned subsidiary, Rocky Mountain Leasing Corporation (RMLC), is required to enter into and maintain an arrangement pursuant to which a third party meeting certain minimum credit rating requirements agrees to make payments sufficient to fund the equity portion of the fixed purchase price of the undivided interests in the Rocky Mountain Pumped Storage Hydroelectric Facility (Rocky Mountain) that RMLC leases from the six Owner Trusts (the "Trusts") formed to effectuate the Rocky Mountain Leasing Arrangements, if Oglethorpe causes RMLC to exercise its option to purchase these interests when the leases expire in 2027. Consequently, RMLC entered into six Equity Funding Agreements with AIG Matched Funding Corp. (collectively, the "AIG Equity Funding Agreements"), which is a wholly owned subsidiary of American International Group, Inc. (AIG), concurrently with the consummation of the Rocky Mountain Lease Arrangements. AIG has guaranteed the obligations of AIG Matched Funding Corp. under the AIG Equity Funding Agreements.

Pursuant to the AIG Equity Funding Agreements, RMLC deposited $57,000,000 with AIG Matched Funding Corp. that was invested in six guaranteed investment contracts that will increase in value during the term of the lease, and at the end of the lease term will have a value equal to the equity portion of the fixed purchase price, or $372,000,000. These investments are reflected on Oglethorpe's condensed unaudited balance sheets as "Deposit on Rocky Mountain transactions", with a balance of $110,044,000 at March 31, 2009.

The operative agreements relating to the Rocky Mountain Lease Arrangements provide that if AIG fails to maintain a credit rating of at least Aa3 from Moody's and AA- from S&P, then AIG Matched Funding Corp. will be required to post collateral having a stipulated credit quality to secure its obligations under the AIG Equity Funding Agreements. Moreover, if AIG fails to maintain a credit rating of at least Baa3 from Moody's and BBB- from S&P, then RMLC must, within 60 days of becoming aware of such fact, enter into replacement Equity Funding Agreements with a financial institution that has credit ratings of at least Aa3 from Moody's or AA- from S&P. In the event that RMLC were not able to enter into replacement Equity Funding Agreements, then RMLC may be required to purchase the Trusts' equity interests from the owners thereof.

In September 2008, Moody's lowered AIG's rating to A2 from Aa3 and S&P lowered AIG's rating to A- from AA-. As a result of the downgrade, AIG Matched Funding Corp. posted collateral in compliance with the AIG Equity Funding Agreements, consisting of securities issued by an instrumentality of the United States government that are rated triple-A in an amount equal to the net present value of its future payment obligations related to the equity portion of the fixed purchase price (the "Collateral Requirement"). In accordance with the terms of the AIG Equity Funding Agreements, the market value of the posted collateral (other than cash) will be determined weekly by an independent third party and AIG Matched Funding Corp. will be required to post additional collateral to the extent that it is determined that the market value of such collateral, together with the cash collateral (if any), has fallen below the Collateral Requirement. According to U.S. Bank National Association, which as collateral agent holds the collateral and provides the weekly valuation thereof, the market value of the collateral was approximately $115,000,000 at March 31, 2009.

Relationship with AMBAC. In addition, the operative agreements require Oglethorpe to maintain surety bonds with a surety bond provider that meets minimum credit rating requirements to secure certain of Oglethorpe's payment obligations under the Rocky Mountain Lease Arrangements. Accordingly, Oglethorpe entered into a surety bond arrangement with AMBAC concurrently with the consummation of the Rocky Mountain Lease Arrangements.

The operative agreements provide that if the surety bond provider fails to maintain a credit rating of at least AA from S&P or Aa2 from Moody's, then Oglethorpe must, within 60 days of becoming aware of such fact, provide (i) a replacement surety bond from a surety bond provider that has such credit ratings, (ii) a letter of credit from a bank with such credit ratings, (iii) other acceptable credit enhancement or (iv) any combination thereof.

On November 19, 2008, S&P lowered AMBAC's credit rating from AA to A. Because AMBAC already had a credit rating of Baa1 from Moody's, such action by S&P triggered the requirement for Oglethorpe to provide the replacement credit enhancement discussed above. Each of the three owner participants have granted Oglethorpe extensions of time to provide this replacement credit enhancement.

Oglethorpe and the owner participants have been negotiating with Berkshire Hathaway Assurance Corporation (Berkshire), rated AAA by S&P and Aa1 by Moody's, since January 2009 on two separate structures that would add new surety bond coverage into the Rocky Mountain Lease Arrangements. Oglethorpe's management believes that, based on progress made thus far, the owner participants will grant further extensions of time as necessary to bring this matter to closure. Oglethorpe does not believe the cost of such replacement credit enhancement will have a material adverse effect on its results of operations or its financial condition.

In the event Oglethorpe is ultimately unable to implement the replacement credit enhancement with any of the three owner participants or further extensions of time are not granted by the owner participants as necessary, then Oglethorpe may be required to purchase the equity interest of the owner participant in the related owner trust if the owner participant exercises such right under the operative agreements relating to the Rocky Mountain Lease Arrangements. Oglethorpe estimates that the current maximum aggregate amount of exposure it would have if it were required to purchase the equity interests of all six owner trusts is approximately $250,000,000, and this amount will begin to decline in 2011 until it reaches zero by the end of the lease term in 2027. This amount is net of the accreted value of the guaranteed investment contracts that were entered into with AIG Matched Funding Corp. in connection with the Rocky Mountain Lease Arrangements. The actual value of the guaranteed investment contracts may be more or less than the accreted value as a result of changes in interest rates and market conditions. In September 2008, AIG Matched Funding Corp. began posting collateral in compliance with the AIG Equity Funding Agreements consisting of securities issued by an instrumentality of the U.S. Government that are rated AAA in an amount approximately equal to 105% of the net present value of its future payment obligation related to the equity portion of the fixed purchase price.

Oglethorpe's inability to timely provide such replacement credit enhancement, or otherwise either obtain additional time from the owner participants or purchase the equity interests, may constitute a cross default or an event of default under certain of Oglethorpe's loan agreements, derivative agreements and other evidences of indebtedness, and the other parties may elect to exercise their rights and remedies under these agreements. Such rights include the right to cease making advances under any loan agreements as a result of any of the foregoing.

Oglethorpe expects to have adequate liquidity to purchase the equity interests, based on the maximum aggregate exposure amount of approximately $250,000,000, if it were required to do so.

(K) New Bond Issuance. In February 2009, Oglethorpe issued $350,000,000 of Series 2009A taxable fixed rate first mortgage bonds for the purposes of financing a portion of construction costs associated with new generation facilities, to enhance existing generation facilities and to provide liquidity for general corporate purposes. The first mortgage bonds were secured under Oglethorpe's Mortgage Indenture.

OGLETHORPE POWER CORPORATION

CONSOLIDATED STATEMENTS OF REVENUES AND EXPENSES

For the years ended December 31, 2008, 2007 and 2006

		2008			2007			2006

		(dollars in thousands)
Operating revenues:
	Sales to Members	$	1,237,649		$	1,149,657		$	1,127,423
	Sales to non-Members		1,111			1,585			1,456

Total operating revenues			1,238,760			1,151,242			1,128,879

Operating expenses:
	Fuel		466,205			415,125			374,144
	Production		277,794			246,675			254,658
	Purchased power		160,133			155,005			179,129
	Depreciation and amortization		119,540			131,434			156,829
	Accretion		17,149			16,169			17,351
	Other		860			(394	)		(39,529	)

Total operating expenses			1,041,681			964,014			942,582

Operating margin			197,079			187,228			186,297

Other income:
	Investment income		30,483			43,157			41,258
	Amortization of deferred gains		5,660			5,660			5,660
	Allowance for equity funds used during construction		3,075			1,802			904
	Other		4,163			4,235			3,592

Total other income			43,381			54,854			51,414

Interest charges:
	Interest on long-term debt and capital leases		211,793			212,003			204,317
	Other interest		6,249			2,253			3,046
	Allowance for debt funds used during construction		(12,259	)		(6,962	)		(3,437	)
	Amortization of debt discount and expense		15,418			15,727			15,584

Net interest charges			221,201			223,021			219,510

Net margin		$	19,259		$	19,061		$	18,201

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

OGLETHORPE POWER CORPORATION

CONSOLIDATED BALANCE SHEETS

December 31, 2008 and 2007

		2008			2007

		(dollars in thousands)
Assets
Electric plant:
	In service	$	5,906,865		$	5,792,476
	Less: Accumulated provision for depreciation		(2,753,954	)		(2,630,522	)

			3,152,911			3,161,954
	Nuclear fuel, at amortized cost		179,020			130,138
	Construction work in progress		307,464			189,102

Total electric plant			3,639,395			3,481,194

Investments and funds:
	Decommissioning fund		201,094			239,974
	Deposit on Rocky Mountain transactions		108,219			101,272
	Bond, reserve and construction funds		4,560			5,614
	Investment in associated companies		43,441			46,449
	Long-term investments		81,550			109,170
	Other, at cost		391			1,502

Total investments and funds			439,255			503,981

Current assets:
	Cash and cash equivalents, at cost		167,659			290,930
	Restricted cash, at cost		10,255			48,124
	Receivables		116,679			60,672
	Inventories, at average cost		175,350			149,871
	Prepayments and other current assets		5,619			4,780

Total current assets			475,562			554,377

Deferred charges:
	Premium and loss on reacquired debt, being amortized		130,013			140,829
	Deferred amortization of capital leases		85,612			91,446
	Deferred debt expense, being amortized		41,905			37,356
	Deferred outage costs, being amortized		27,137			29,833
	Deferred tax assets		48,000			72,000
	Deferred asset retirement obligations costs, being amortized		60,310			—
	Deferred interest rate swap termination fees, being amortized		33,286			—
	Deferred depreciation expense		42,955			14,318
	Other		21,022			11,986

Total deferred charges			490,240			397,768

Total assets		$	5,044,452		$	4,937,320

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

		2008			2007

		(dollars in thousands)
Equity and Liabilities
Capitalization:
	Patronage capital and membership fees	$	535,829		$	516,570
	Accumulated other comprehensive deficit		(1,348	)		(32,691	)

			534,481			483,879
	Long-term debt		3,278,856			3,291,424
	Obligations under capital leases		236,067			260,943
	Obligation under Rocky Mountain transactions		108,219			101,272

Total capitalization			4,157,623			4,137,518

Current liabilities:
	Long-term debt and capital leases due within one year		110,647			143,400
	Short-term borrowings		140,000			—
	Accounts payable		29,305			41,621
	Accrued interest		34,539			20,153
	Accrued and withheld taxes		18,827			7,122
	Other current liabilities		28,081			17,311

Total current liabilities			361,399			229,607

Deferred credits and other liabilities:
	Gain on sale of plant, being amortized		33,536			36,011
	Net benefit of Rocky Mountain transactions, being amortized		57,336			60,521
	Asset retirement obligations		281,458			265,326
	Accumulated retirement costs for other obligations		49,675			53,327
	Deferred liability associated with retirement obligations, being amortized		—			5,568
	Interest rate swap arrangements		—			32,806
	Long-term contingent liability		48,000			72,000
	Members' advances		5,000			—
	Other		50,425			44,636

Total deferred credits and other liabilities			525,430			570,195

Total equity and liabilities		$	5,044,452		$	4,937,320

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

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

OGLETHORPE POWER CORPORATION

CONSOLIDATED STATEMENTS OF CAPITALIZATION

December 31, 2008 and 2007

				2008			2007

				(dollars in thousands)
Long-term debt:
	Mortgage notes payable to the Federal Financing Bank ("FFB") at interest rates varying from 2.70% to 8.43% (average rate of 5.59% at December 31, 2008) due in quarterly installments through 2042			$	1,652,952		$	1,661,751
	Mortgage notes payable to Rural Utilities Service ("RUS") at an interest rate of 5% due in monthly installments through 2020				9,269			9,872
	Mortgage bonds payable:
	*Series 2006
		Term Bonds, 5.534% due 2031 through 2035			300,000			300,000
	*Series 2007
		Term Bonds, 6.191% due 2024 through 2031			500,000			500,000
	Mortgage notes issued in connection with the sale of pollution control revenue bonds through the Development Authority of Appling, Burke, Heard and Monroe County, Georgia:
		*Series 1992A Monroe
			Serial bonds, 6.70% to 6.80%, due serially from 2009 through 2012		37,702			45,696
		*Series 1993A Burke
			Adjustable tender bonds, fully redeemed May 2008		—			136,771
		*Series 1994A
			Adjustable tender bonds, fully redeemed May 2008		—			85,314
		*Series 2002 and 2002C
			Adjustable tender bonds, fully redeemed January 2008		—			30,075
		*Series 2003A Burke, Heard, Monroe and 2003B Burke
			Auction rate bonds, 1.79%, due 2024		95,230			95,230
		*Series 2004 Burke and Monroe
			Auction rate bonds, 1.80%, due 2020		11,525			11,525
		*Series 2005 Burke and Monroe
			Auction rate bonds, 1.79%, due 2040		15,865			15,865
		*Series 2006A Monroe, 2006B-1 through B-4 Burke
			Adjustable tender bonds, fully redeemed September 2008		—			197,945
		*Series 2006B Monroe, 2006C-1 and 2006C-2 Burke
			Term rate bonds, 4.63% through March 31, 2010, due 2036 through 2037		133,550			133,550
		*Series 2007 A Appling and Monroe, 2007B Appling and Burke, 2007C through F Burke
			Term rate bonds, 4.75% through March 31, 2011, due 2038 through 2040		135,223			178,228
		*Series 2008A through C Burke
			Fixed rate bonds, 5.30% to 5.70%, due 2032 through 2043		255,035			—
		*Series 2008E Burke
			Fixed rate bonds, 7.00%, due 2020 through 2023		144,750			—
		*Series 2008F Burke and 2008A Monroe
			Term rate bonds, 6.50% through March 31, 2011, due 2038 through 2039		41,125			—
		*Series 2008G Burke
			Term rate bonds, 6.75% through March 31, 2012, due 2039		22,325			—
	CoBank, ACB notes payable:
		*Transmission mortgage note payable: fixed at 3.72% through March 9, 2010, due in bimonthly installments through November 1, 2018			1,388			1,457
		*Transmission mortgage note payable: fixed at 3.72% through March 9, 2010, due in bimonthly installments through September 1, 2019			5,524			5,759

Total long-term debt					3,361,463			3,409,038
Obligations under capital leases					264,107			286,729
Obligation under Rocky Mountain transactions, long-term					108,219			101,272
Patronage capital and membership fees					535,829			516,570
Accumulated other comprehensive deficit					(1,348	)		(32,691	)

	Subtotal				4,268,270			4,280,918
		Less: long-term debt and capital leases due within one year			(110,647	)		(143,400	)

Total capitalization				$	4,157,623		$	4,137,518

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

OGLETHORPE POWER CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31, 2008, 2007 and 2006

				2008			2007			2006

				(dollars in thousands)
Cash flows from operating activities:
	Net margin			$	19,259		$	19,061		$	18,201

	Adjustments to reconcile net margin to net cash provided by operating activities:
		Depreciation and amortization, including nuclear fuel			213,804			222,334			233,682
		Accretion cost			17,149			16,169			17,351
		Amortization of deferred gains			(5,660	)		(5,660	)		(5,660	)
		Allowance for equity funds used during construction			(3,075	)		(1,802	)		(904	)
		Deferred outage costs			(30,926	)		(36,550	)		(31,594	)
		Loss (gain) on sale of investments			40,299			(8,610	)		(12,990	)
		Regulatory deferral of costs associated with nuclear decommissioning			(48,488	)		3,631			5,055
		Other			(16	)		(423	)		(1,024	)
	Change in operating assets and liabilities:
		Receivables			(37,285	)		28,946			7,416
		Inventories			(25,479	)		(13,875	)		(41,422	)
		Prepayments and other current assets			(1,062	)		(323	)		(221	)
		Accounts payable			(1,582	)		1,050			(20,074	)
		Accrued interest			14,386			(34,336	)		268
		Accrued and withheld taxes			11,705			(34,633	)		12,714
		Other current liabilities			(8,268	)		8,051			(924	)
		Settlement of interest rate swaps			(33,771	)		—			—

			Total adjustments		101,731			143,969			161,673

Net cash provided by operating activities					120,990			163,030			179,874

Cash flows from investing activities:
	Property additions				(353,831	)		(194,739	)		(134,518	)
	Activity in decommissioning fund—Purchases				(751,201	)		(535,898	)		(733,768	)
	—Proceeds				743,728			526,832			725,387
	Activity in bond, reserve and construction funds—Purchases				(78	)		(5,616	)		(1,124	)
	—Proceeds				1,132			6,502			2,067
	Increase (decrease) in restricted cash and cash equivalents				37,869			(29,812	)		(2,156	)
	Decrease (increase) in other short-term investments				—			—			231,798
	Increase (decrease) in investment in associated organizations				4,788			(1,491	)		(3,869	)
	Activity in other long-term investments—Purchases				(185,054	)		(649,770	)		(487,387	)
	—Proceeds				193,413			660,956			418,056
	Increase (decrease) in Members' advances				5,000			—			(74,471	)
	Other				(4,507	)		(5,265	)		(894	)

Net cash used in investing activities					(308,741	)		(228,301	)		(60,879	)

Cash flows from financing activities:
	Long-term debt proceeds				523,431			755,135			631,495
	Long-term debt payments				(593,879	)		(775,573	)		(486,914	)
	Increase in notes payable				140,000			—			—
	Debt related costs				(9,210	)		(51,693	)		(13,445	)
	Other				4,138			4,575			2,892

Net cash provided by (used in) financing activities					64,480			(67,556	)		134,028

Net increase (decrease) in cash and temporary cash investments					(123,271	)		(132,827	)		253,023
Cash and temporary cash investments at beginning of period					290,930			423,757			170,734

Cash and temporary cash investments at end of period				$	167,659		$	290,930		$	423,757

Supplemental cash flow information:
Cash paid for—
	Interest (net of amounts capitalized)			$	191,397		$	241,632		$	203,658

Supplemental disclosure of non-cash investing and financing activities:
	Plant expenditures included in ending accounts payable			$	(10,529	)	$	10,099		$	(5,081	)

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

OGLETHORPE POWER CORPORATION

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

For the years ended December 31, 2008, 2007 and 2006

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2008, 2007 and 2006

Oglethorpe Power Corporation ("Oglethorpe") is an electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta, GA. Oglethorpe is owned by 38 retail electric distribution cooperative members (the "Members"). The wholesale electric power provided by Oglethorpe consists of a combination of generating units totaling 4,744 megawatts ("MW") of capacity and power purchase agreements totaling approximately 300 MW of capacity. These Members in turn distribute energy on a retail basis to approximately 4.1 million people.

Oglethorpe's consolidated financial statements as of, and for the period ended December 31, 2008 include Oglethorpe's accounts and the accounts of Oglethorpe's majority-owned and controlled subsidiaries. Oglethorpe has determined that there are no accounts of variable interest entities for which it is the primary beneficiary. This means that Oglethorpe's accounts are combined with the subsidiaries' accounts. Oglethorpe has eliminated any intercompany profits and transactions in consolidation.

Oglethorpe follows generally accepted accounting principles ("GAAP") in the United States. It tracks its accounts in accordance with the Uniform System of Accounts of the Federal Energy Regulatory Commission ("FERC") as modified and adopted by the Rural Utilities Service ("RUS").

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of December 31, 2008 and 2007 and the reported amounts of revenues and expenses for each of the three years ending December 31, 2008. Actual results could differ from those estimates.

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

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

The table below provides a detail of the beginning and ending balance for each classification of other comprehensive deficit along with the amount of any reclassification adjustments included in margin for each of the years presented in the Statement of Patronage Capital and Membership Fees and Accumulated Other Comprehensive Deficit (see Note 2). Oglethorpe's effective tax rate is zero; therefore, all amounts below are presented net of tax.

Oglethorpe is required under the Mortgage Indenture to produce a Margins for Interest ("MFI") Ratio of at least 1.10. For the years 2006, 2007 and 2008, Oglethorpe achieved a MFI ratio of 1.10.

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

Operating revenues from non-Members consisted primarily from services provided to Oglethorpe's former Member Flint EMC.

The following table reflects Members whose revenues accounted for 10% or more of Oglethorpe's total operating revenues in 2008, 2007 and 2006:

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.

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 2008, 2007 and 2006 amounted to $48,987,000, $50,138,000, and $45,299,000, respectively.

Contracts with the U.S. Department of Energy ("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 January 1998 as required by the contracts, and Georgia Power Company ("GPC"), as agent for the co-owners of the plants, is pursuing legal remedies against DOE for breach of contract. An on-site dry storage facility for Plant Hatch is operational and can be expanded to accommodate spent fuel through the life of the plant. Sufficient storage capacity is available at Plant Vogtle in the spent fuel pools to maintain full core discharge capacity for both units until 2015.

On July 9, 2007, the U.S. Court of Federal Claims found in favor of Southern Company and awarded damages in the amount of $59,900,000 for Plant Hatch and Plant Vogtle. Oglethorpe's share of the award is $17,980,000. The decision has been appealed by the DOE. No amounts have been recognized in the financial statements as of December 31, 2008. The final outcome of this matter cannot be determined at this time. Oglethorpe's rate-making treatment of such future award received would be passed on to its Members.

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

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

Under SFAS No. 71, Oglethorpe may record an offsetting regulatory asset or liability to reflect the difference in timing of recognition of the costs of decommissioning for financial statement purposes and for ratemaking purposes for both the cumulative effect of adoption and for future periods timing differences. RUS has approved Oglethorpe's implementation of the provisions of SFAS No. 71 with respect to the cumulative effect of adoption and with respect to timing differences between cost recognition under SFAS No. 143 or FIN 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 FIN No. 47. Oglethorpe estimates an annual increase of approximately $2,000,000 over the next several years of the regulatory asset.

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

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

The following tables reflect the details of the Asset Retirement Obligations included in the balance sheets for the years 2008 and 2007.

As previously discussed, Oglethorpe is deferring the timing differences between cost recognition under SFAS No. 143 and cost recovery for ratemaking purposes. Increases and decreases to the regulatory asset are reflected on the accompanying balance sheets as "Deferred asset retirement

obligations costs, being amortized" and increases or decreases to the regulatory liability are reflected as "Deferred liability associated with retirement obligations, being amortized" under the caption "Deferred credits and other liabilities."

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

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, 2008 and 2007, equity and fixed income securities, respectively comprised 51% and 49%, respectively of the external funds. The NRC's minimum external funding requirements are based on a generic estimate of the cost to decommission the radioactive portions of a nuclear unit based on the size and type of reactor. Oglethorpe has filed plans with the NRC to ensure that, over time, the deposits and earnings of the external trust funds will provide the minimum funding amounts prescribed by the NRC. Oglethorpe also maintains internal reserves that can be transferred to the external trust fund as needed. All realized gains (losses) and earned income associated with the nuclear decommissioning fund are reflected within the "Cash flows from operating activities" and "Cash flows from investing activities" sections, respectively, of Oglethorpe's cash flow statement. Purchases, including reinvestments of earned income, and sales are reflected in the "Activity in decommissioning fund" line of the "Cash flows from investing activities" section of the cash flow statement. For the periods ending December 31, 2008 and 2007, realized gains (losses) and earned income totaled ($32,239,000) and $18,870,000, respectively.

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

Oglethorpe has not recorded any provision for decommissioning during the years 2008, 2007 and 2006 because the balance in the decommissioning trust fund at December 31, 2008 is expected to be sufficient to fund the nuclear decommissioning obligation in future years. In projecting future costs, the escalation rate for labor, materials and equipment was assumed to be 2.9%. Oglethorpe assumes a 6.85% earnings rate for its decommissioning trust fund assets. Since inception (1990), the nuclear

decommissioning trust fund has produced a return in excess of 6.22% even though Oglethorpe experienced realized losses on its decommissioning trust fund assets in 2008. A new decommissioning site study will be performed in late 2009. The combination of the results from the decommissioning site study along with investment returns during 2009 will be utilized to assess whether additional decommissioning collections will be required in future years. Oglethorpe's management believes that any increase in cost estimates of decommissioning or declines in investment earnings can be recovered in future rates.

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 2008, 2007 and 2006 were as follows:

Depreciation expense for the years 2008, 2007 and 2006 was $119,067,000, $130,962,000, and $156,358,000, respectively. In 2007, under the provisions of SFAS No. 71, Oglethorpe began deferring the difference between Plant Vogtle depreciation expenses based on the current 40-year operating license versus depreciation expenses based on the applied for 20-year license extension. For further discussion of the depreciation deferral, see Note 1(s).

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, 2008, 2007 and 2006, the allowance for funds used during construction ("AFUDC") rates used were 6.10%, 6.24% and 6.21%, 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.

Bond, reserve and construction funds for pollution control revenue bonds ("PCBs") are maintained as required by Oglethorpe's bond agreements. Bond funds serve as payment clearing accounts, reserve funds maintain amounts equal to the maximum annual debt service of each bond issue and construction funds hold bond proceeds for which construction expenditures have not yet been made. As of December 31, 2008 and 2007, all of the funds were invested in either U.S. Government securities or money market accounts.

Oglethorpe considers all temporary cash investments purchased with an original 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.

The balances at December 31, 2008 and 2007, $10,255,000 and $48,124,000, respectively, were utilized in January 2009 and 2008 for payment of principal on certain PCBs, respectively.

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, 2008 and 2007, fossil fuels inventories were $72,891,000 and $55,981,000, respectively. Inventories for spare parts at December 31, 2008 and 2007 were $102,459,000 and $93,890,000, respectively.

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

Oglethorpe accounts for debt issuance costs as deferred debt expense. Deferred debt expense is being amortized to expense on a straight-line basis over the life of the respective debt issues, which approximates the effective interest rate method.

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

As of December 31, 2008, the remaining amortization periods for debt issuance costs and premium and loss on reacquired debt range from approximately 1 to 34 years.

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.

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

In March 2008, Oglethorpe terminated both the AIG Financial Products Corp. ("AIG-FP") and JPMorgan Chase Bank ("JPMC") interest rate swap arrangements. Oglethorpe made a termination payment to AIG-FP of $36,611,000 and received a termination payment of $2,840,000 from JPMC. The amounts are recorded as a regulatory asset and liability, respectively, in accordance with SFAS No. 71, and are being amortized over the remaining life of the Series 1993A and Series 1994A PCBs, or 2016 and 2019, respectively. The JPMC termination payment is reflected in the table below as "Other regulatory liabilities" and is included on the balance sheet under the caption "Deferred credits and other liabilities" in the line item "Other".

In December 2008, Oglethorpe recorded an other-than-temporary impairment on $7,300,000 of its auction rate securities that had previously been recorded as a temporary impairment, issued by Anchorage Finance Sub-Trust, an investment vehicle of AMBAC Assurance Corp ("AMBAC"), as a result of failed auctions, credit rating downgrades and the conversion of such securities to auction market preferred shares by AMBAC. The impairment is recorded as a regulatory asset under the provisions of SFAS No. 71 and is reflected as "Deferred investment impairment losses in the table below and is included on the balance sheet, under the caption "Deferred charges", in the line item "Other." This amount will be amortized as a charge to income over seven years.

Effective July 1, 2007, Oglethorpe under the provisions of SFAS No. 71 began deferring the difference between Plant Vogtle depreciation expenses based on the current 40-year operating license versus depreciation expenses based on the applied for 20-year license extension. The difference in the depreciation expenses are reflected in the "Deferred depreciation expense" line item in the table below. The deferral amount is being amortized to deprecation expense over the remaining life of Plant Vogtle beginning in the year that the license extension is approved by the NRC. The approval from the NRC is expected in 2009.

Other regulatory assets in the table below are included on the balance sheet under the caption "Deferred charges" in the line item "Other."

The following regulatory assets and liabilities are reflected on the accompanying balance sheets as of December 31, 2008 and 2007:

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 39 years, except for the asset retirement obligations regulatory assets which have a recovery period of 11 to 39 years. The remaining refund period for the regulatory liabilities are approximately 18 years for the Rocky Mountain transactions and over the lives of the plants for accumulated retirement costs for other obligations.

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

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

In October 2008, the Financial Accounting Standards Board ("FASB") issued FASB Staff Position (FSP) No. 157-3, "Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active." FSP No. 157-3 clarifies the definition of fair value as defined in SFAS No. 157 by stating that a transaction price is not necessarily indicative of fair value in a market that is not active or in a forced liquidation or distressed sale. Rather, if the company has the ability and intent to hold the asset, the company may use its assumptions about future cash flows and appropriately adjusted discount rates in measuring fair value of the asset. The adoption of FSP No. 157-3 did not have a material affect on Oglethorpe's results of operations, cash flows or financial condition.

In March 2008, the FASB issued SFAS No. 161, "Disclosures about Derivative Instruments and Hedging Activities." The new standard is intended to improve financial reporting about derivative instruments and hedging activities by requiring enhanced disclosures to enable investors to better understand their effects on an entity's financial position, financial performance, and cash flows. The new standard is effective January 1, 2009. The adoption of SFAS No. 161 is not expected to have any impact on Oglethorpe's results of operations, cash flows or financial condition.

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

In November 2007, the FASB issued a one-year deferral for the implementation of SFAS No. 157 "Fair Value Measurements" for non-financial assets and non-financial liabilities that are recognized or

disclosed at fair value in the financial statements on a nonrecurring basis. The deferral is applicable for asset retirement obligations measured at fair value upon initial recognition under FASB Statement No. 143 "Accounting for Asset Retirement Obligations", or upon a remeasurement event. Oglethorpe adopted SFAS No. 157 for non-financial assets and non-financial liabilities with no material effect on its results of operations or financial condition. Oglethorpe adopted SFAS No. 157 for financial assets and liabilities effective January 1, 2008 with no material effect on its results of operations, cash flows or financial condition.

Adoption of Financial Accounting Standard (SFAS) No. 157, "Fair Value Measurements." On January 1, 2008, Oglethorpe adopted SFAS No. 157. SFAS No. 157 defines fair value, establishes a framework for measuring fair value in accordance with GAAP, and expands disclosures about fair value measurements. SFAS No. 157 does not require any new fair value measurements.

SFAS No. 157 is applied prospectively as of the first interim period for the fiscal year in which it is initially adopted, except for limited retrospective adoption for the following three items:

The impact of adoption in these areas would be applied as a cumulative-effect adjustment to opening retained earnings, measured as the difference between the carrying amounts and the fair values of relevant assets and liabilities at the date of adoption. Oglethorpe does not have any of the three aforementioned items, therefore no transition adjustment will be recorded.

SFAS No. 157 establishes a three-tier fair value hierarchy which prioritizes the inputs used in measuring fair value as follows:

As required by SFAS No. 157, assets and liabilities measured at fair value are based on one or more of the following three valuation techniques:

The table below details assets and liabilities measured at fair value on a recurring basis (dollars in thousands).

The following tables present assets and liabilities measured at fair value on a recurring basis using significant unobservable inputs for the twelve months ended December 31, 2008.

Realized gains and losses included in earnings for the period are reported in other income.

Based on market conditions including the failure of various auctions for auction rate securities in which Oglethorpe invested, Oglethorpe changed its valuation technique for auction rate securities to an income approach using a discounted cash flow model based on projected cash flows at current rates and adjusted for illiquidity premiums based on discussion with market participants. Accordingly, these investments, which are included in long-term investments on the consolidated balance sheets as their maturity dates are greater than one year from the balance sheet date, changed from Level 1 to Level 3 within the SFAS No. 157's three-tier fair value hierarchy for the period ended December 31, 2008. At December 31, 2008, Oglethorpe held auction rate securities with maturity dates ranging from March 15, 2028 to December 1, 2045.

Based on the fair value determined from the discounted cash flow analysis, a temporary impairment of approximately $1,657,000 was recorded in other comprehensive deficit. The various assumptions Oglethorpe utilizes to determine the fair value of its auction rate securities investments will vary from period to period based on the prevailing economic conditions. If the market for Oglethorpe's auction rate securities investments continues to deteriorate, Oglethorpe may need to increase the illiquidity premium used in preparing a discounted cash flow model for these securities. A

25 basis point increase in the illiquidity premium used to determine the fair value of these investments at December 31, 2008, would have resulted in a decrease in the fair value of Oglethorpe's auction rate securities investments by approximately $1,570,000.

These investments were rated Aaa by Moody's Investors Service ("Moody's") and AAA by Standard and Poor's ("S&P") as of December 31, 2008. Therefore, it is expected that the investments will not be settled at a price less than par value. Because Oglethorpe has the ability and intent to hold these investments until a recovery of its original investment value, it considered the investment to be temporarily impaired at December 31, 2008.

In December 2008, Oglethorpe recorded an other-than-temporary impairment on $7,300,000 of its auction rate securities that had previously been recorded as a temporary impairment, issued by Anchorage Finance Sub-Trust, an investment vehicle of AMBAC, as a result of failed auctions, credit rating downgrades and the conversion of such securities to auction market preferred shares by AMBAC. The impairment was recorded as a regulatory asset under the provisions of SFAS No. 71 and are reflected on the balance sheet, under the caption "Deferred charges", in the line item "Other."

The estimated fair values of Oglethorpe's long-term debt at December 31, 2008 and 2007 were as follows (in thousands):

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. Oglethorpe's three primary sources of long term debt consist of First Mortgage Bonds, Pollution Control Revenue Bonds and long term debt issued by the Federal Financing Bank. Oglethorpe also has small amounts of long term debt provided by the RUS and by CoBank. The valuations for the First Mortgage Bonds and the Pollution Control Revenue Bonds are provided by a third-party investment banking firm. These valuations are based on market prices for similar debt in active markets. Valuations for debt issued by the Federal Financing Bank and RUS are based on U.S. Treasury rates as of December 31, 2008 (plus a spread of ¹/8 percent). The additional spread of ¹/8 percent is reflective of the "cost" RUS attributes to making these loans to an "A" rated borrower such as Oglethorpe. Oglethorpe uses an interest rate quote sheet provided by CoBank for valuation of the CoBank debt. The quotes contained in CoBank's rate sheet are adjusted for Oglethorpe's "A" credit rating.

Oglethorpe uses the methods and assumptions described below to estimate the fair value of each class of financial instruments. For cash and cash equivalents, restricted cash and receivables the carrying amount approximates fair value because of the short-term maturity of those instruments.

Oglethorpe accounts for derivatives under SFAS No. 133 as amended. The standard establishes accounting and reporting requirements for derivative instruments, including certain derivative instruments embedded in other contracts, and hedging activities. It requires the recognition of certain derivatives as assets or liabilities on Oglethorpe's balance sheet and measurement of those instruments

at fair value. The accounting treatment of changes in fair value is dependent upon whether or not a derivative instrument is classified as a hedge and if so, the type of hedge.

In 1993, Oglethorpe entered into two interest rate swap arrangements with AIG-FP, for the purpose of securing a fixed rate lower than otherwise would have been available to Oglethorpe had it issued fixed rate bonds at that time. Under these swap arrangements, Oglethorpe made payments to the counterparty based on the notional principal at a contractual fixed rate and the counterparty made payments to Oglethorpe based on the notional principal at the existing variable rate of the refunding bonds. The differential to be paid or received was accrued as interest rates changed and was recognized as an adjustment to interest expense. For the Series 1993A and Series 1994A notes, the notional principal at December 31, 2007 was $164,515,000 and $102,620,000, respectively. The notional principal amount was used to measure the amount of the swap payments and did not represent additional principal due to the counterparty. A portion (16.86%) of the AIG-FP interest rate swap arrangements were assumed by GTC in connection with a corporate restructuring. Oglethorpe classified its portion of the two interest rate swap arrangements, pursuant to SFAS No. 133, as cash flow hedges. In March 2008, Oglethorpe terminated the AIG-FP swaps. The termination payment to AIG-FP of $36,611,000 is recorded as a regulatory asset in accordance with SFAS No. 71 and is being amortized to expense over the remaining life of the Series 1993A notes and Series 1994A notes, or 2016 and 2019, respectively.

Oglethorpe entered into swap arrangements with JPMC in 2006. These swaps used as notional principal, Oglethorpe's 83.14% share of the Series 1993A and Series 1994A bonds ($136,771,000 and $85,314,000 respectively at December 31, 2007) and were designed to convert the contractual variable rate of interest Oglethorpe received under the swaps with AIG-FP to a longer-term contractual variable rate of interest Oglethorpe received from JPMC. In March 2008, Oglethorpe terminated the JPMC swaps. The termination payment received from JPMC of $2,840,000 is recorded as a regulatory liability in accordance with SFAS No. 71 and is being amortized to expense over the remaining life of the Series 1993A notes and Series 1994A notes, or 2016 and 2019, respectively.

Oglethorpe has entered into natural gas financial contracts for managing its exposure to fluctuations in the market price of natural gas. The fair value of Oglethorpe's natural gas financial contracts is based on the quoted market value for such natural gas financial contracts. At December 31, 2008, Oglethorpe's estimated fair value of these natural gas contacts was an unrealized loss of $18,836,000. Consistent with Oglethorpe's rate-making treatment for energy costs which are flowed-through to the Members, this unrealized loss is reflected as an unbilled receivable on Oglethorpe's balance sheet.

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, 2008 and 2007. All realized and unrealized gains and losses are determined using the specific identification method. Approximately 100% 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 trust fund. Consistent with Oglethorpe's ratemaking, unrealized gains and losses from the decommissioning trust fund are recorded as an increase or decrease to the regulatory asset.

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

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, 2008 and 2007 are as follows:

The following table summarizes the realized gains and losses and proceeds from sales of securities for the years ended December 31, 2008, 2007 and 2006:

Investments in associated companies were as follows at December 31, 2008 and 2007:

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

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

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 ("GIC") 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 to the funding of the GICs, the proceeds also funded the Payment Undertaking Agreements with Rabobank Nederland. RMLC paid $640,611,000 to fund these Payment Undertaking Agreements with Rabobank whose senior debt obligations are rated AAA by S&P and Aaa by Moody's. In return, Rabobank undertook to pay all of RMLC's periodic basic rent payments under the Facility Subleases 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. RMLC's corresponding lease obligations have been extinguished for financial reporting purposes. RMLC remains liable for all payments of basic rent 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. In 2009, RMLC would be required to make basic rent payments totaling $56,954,000 to the owner trusts if the Payment Undertaker failed to make such payment. The fair value amount relating to the guarantee of basic rent payments is immaterial principally due to the high credit rating of the Payment Undertaker.

The operative agreements relating to the Rocky Mountain Lease transactions require Oglethorpe to maintain a surety bond with a surety bond provider that meets minimum credit rating requirements to secure certain of Oglethorpe's payment obligations under the Rocky Mountain Lease transactions. Accordingly, Oglethorpe entered into a surety bond agreement with AMBAC concurrently with the consummation of the Rocky Mountain Lease transactions. The operative agreements relating to the Rocky Mountain Lease transactions provide that the surety bond provider must maintain a credit rating of at least Aa2 from Moody's or AA from S&P, and if such rating is not maintained, then Oglethorpe must, within 60 days of becoming aware of such fact, provide (i) a replacement surety bond from a surety bond provider that has such credit ratings, (ii) a letter of credit from a bank with such credit ratings, (iii) other acceptable credit enhancement or (iv) any combination thereof.

On November 19, 2008, S&P lowered AMBAC's credit rating from AA to A. Because AMBAC already had a credit rating of Baa1 from Moody's, such action by S&P triggered the requirement for Oglethorpe to provide the replacement credit enhancement discussed above. Each of the three owner participants has granted an extension of time to provide such replacement credit enhancement until March 31, 2009.

Oglethorpe has reached an agreement in concept with Berkshire Hathaway Assurance Corporation ("Berkshire"), rated AAA and Aaa by S&P and Moody's, respectively, to provide the required replacement credit enhancement and is working with Berkshire and the owner participants to meet the deadline noted above. Oglethorpe's management believes that, based on progress made thus far, the owner participants will grant further extensions of time as necessary to bring this matter to closure. Oglethorpe does not believe the cost of such replacement credit enhancement will have a material adverse effect on its results of operation or its financial condition.

In the event any further extensions of time are not granted by the owner participants as necessary or Oglethorpe is ultimately unable to implement the replacement credit enhancement, then Oglethorpe may be required to purchase the equity interests of the non-extending owner participants in the related owner trusts if the owner participants exercise such right under the operative agreements relating to the Rocky Mountain lease transactions. Oglethorpe estimates that the current maximum aggregate amount of exposure it would have if it were required to purchase the equity interests of all six owner trusts is

approximately $250,000,000, and this amount will begin to decline in 2011 until it reaches zero by the end of the lease term in 2027. This amount is net of the accreted value of the guaranteed investment contracts that were entered into with AIG Matched Funding Corp. in connection with the Rocky Mountain lease transactions. The actual value of the guaranteed investment contracts may be more or less than the accreted value as a result of changes in interest rates and market conditions. In September 2008, AIG Matched Funding Corp. began posting collateral in compliance with the AIG Equity Funding Agreements consisting of securities issued by an instrumentality of the U.S. Government that are rated AAA in an amount approximately equal to 105% of the net present value of its future payment obligation related to the equity portion of the fixed purchase price.

Oglethorpe's inability to timely provide such replacement credit enhancement, or otherwise either obtain additional time from the owner participants or purchase their equity interests, may constitute a cross default or an event of default under certain of Oglethorpe's loan agreements, derivative agreements and other evidences of indebtedness, and the other parties thereto may elect to exercise their rights and remedies thereunder. Such rights include the right to cease making advances under any loan agreements as a result of any of the foregoing.

Oglethorpe expects to have adequate liquidity to purchase the equity interests, based on the maximum aggregate exposure amount of approximately $250,000,000, if Oglethorpe were required to do so.

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

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

Although Oglethorpe believes that its treatment of non-member sales as patronage-sourced income is appropriate, this treatment has not been examined by the Internal Revenue Service. If this treatment was not sustained, Oglethorpe believes that the amount of taxes on such non-member sales, after allocating related expenses against the revenues from such sales, would not have a material adverse effect on its financial condition or results of operations and cash flows.

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

There is a current tax benefit of $110,000 for refundable alternative minimum tax ("AMT") for the year ended December 31, 2008.

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:

The components of the net deferred tax assets as of December 31, 2008 and 2007 were as follows:

As of December 31, 2008, Oglethorpe has federal tax net operating loss ("NOLs") carryforwards and alternative minimum tax ("AMT") credits as follows:

The NOL expiration dates start in the year 2009 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 2007 to 2008 was the result of the reduction in deferred tax assets due to the utilization and expiration of tax credits, net operating losses and the implementation of FIN 48.

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

Oglethorpe and its subsidiaries file a U.S. federal consolidated income tax return. The U.S. federal statute of limitations remains open for the year 2005 forward. State jurisdictions have statutes of limitations generally ranging from three to five years from the filing of an income tax return. The state impact of any federal changes remains subject to examination by various states for a period of up to one year after formal notification to the states. Years still open to examination by tax authorities in major state jurisdictions include 2005 forward.

As a result of the adoption of FIN 48, Oglethorpe recognized a $96,000,000 increase in the liability for unrecognized tax benefits. This change in the liability resulted in no decrease to the January 1, 2008 balance of patronage capital as the effects were offset by recognition of deferred tax assets. During each of the third quarters of 2007 and 2008, one of the three open years expired. Accordingly, this liability and related deferred tax asset was reduced by $24,000,000 during each third quarter. Oglethorpe is carrying forward significant regular tax and AMT NOLs. Therefore, any regular tax liability in the open years related to the uncertain tax position would be offset by regular NOLs. However, Oglethorpe would be liable for the portion of AMT for this period that is not allowed to be offset by the AMT NOLs. In the current open years, Oglethorpe's exposure is not material to its consolidated results of operations, cash flows or financial position.

Oglethorpe recognizes accrued interest with uncertain tax positions in interest expense in the consolidated statements of revenues and expenses. As of December 31, 2008, Oglethorpe has recorded approximately $440,000 for interest in the accompanying balance sheet. It is expected that the amount of unrecognized tax benefits will change in the next twelve months; however, Oglethorpe does not expect the change to have a significant impact on its results of operations, its financial position or its effective tax rate.

The unrecognized tax benefit reconciliation from beginning balance to ending balance is as follows for the years 2008 and 2007:

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, 2008 are as follows:

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, 2008, the weighted average interest rate on the Doyle lease obligation was 5.98%.

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.

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

In April 2008, Oglethorpe converted $133,550,000 of its Series 2006 bonds and $181,890,000 of its Series 2007 bonds from an auction rate mode to a term rate mode of interest using 2-year and 3-year put bonds that will remarket in April 2010 and April 2011. The Series 2006 bonds have bullet maturities in 2036 and 2037. The Series 2007 bonds have bullet maturities in 2038, 2039 and 2040.

In August 2008, Oglethorpe refinanced $255,035,000 of PCBs that were previously in a weekly variable rate demand bond ("VRDB") mode through the issuance of $255,035,000 of Series 2008A through C refunding bonds which have maturities of 2033 and 2043. The proceeds from the issuance of the Series 2008A through C refunding bonds were used to repay $260,000,000 of commercial paper that had been issued in April and May of 2008 to redeem the VRDBs.

In a transaction that closed in December 2008, Oglethorpe refinanced another $248,350,000 of PCBs, including $238,095,000 of Series 2006 PCBs that were previously in commercial paper VRDB mode and $10,255,000 of annual principal that matured in January 2009. Of the Series 2008A and 2008D through G refunding bonds, $103,600,000 were issued in a term rate mode and the remaining $144,750,000 were issued with rates fixed to maturity. The Series 2008 Term Rate Refunding Bonds have bullet maturities in 2038, 2039 and 2040. The Series 2008 Fixed Rate Refunding Bonds are subject to scheduled mandatory redemption in 2020, 2021 and 2022, and have a final maturity in 2023. In addition, GTC has an assumed obligation of the Series 2008 bonds of $40,150,000.

In connection with a 1997 corporate restructuring, 16.86% of the then outstanding PCBs were assumed by GTC, including approximately $1,700,000 of the PCBs that were refinanced in December 2008. GTC participated in this refinancing as it had the right to do so pursuant to an agreement between the companies.

Maturities for long-term debt and amortization of the capital lease obligations through 2013 are as follows:

The weighted average interest rate for long-term debt and capital leases was 5.58% at December 31, 2008.

Oglethorpe has a $50,000,000 committed line of credit with CFC which matures in October 2011 and another $50,000,000 committed line of credit with CoBank which matures December 2009. 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, 2008 or 2007.

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 five-year $450,000,000 committed backup line of credit that matures in July 2012. In addition to providing dedicated support for commercial paper, the facility may also be used for working capital and for general corporate purposes and to issue letters of credit in an aggregate amount up to $50,000,000. However, any amounts drawn under the facility for working capital or general purposes or for purposes of supporting issued letters of credit will reduce the amount of commercial paper that Oglethorpe is authorized to issue.

In September 2008, Oglethorpe issued $240,000,000 of commercial paper and used the proceeds to redeem $238,350,000 of Series 2006 PBCs (of which GTC had a $40,150,000 assumed obligation). In November 2008, Oglethorpe advanced $240,000,000 under its commercial paper backup credit facility and used the proceeds to repay the commercial paper issued in September 2008. The $240,000,000 advanced under the backup credit facility was repaid with proceeds from the Series 2008 refunding bonds Oglethorpe issued in December 2008. At December 31, 2008, there was $140,000,000 outstanding

on this line of credit which was repaid in January 2009. There was no balance outstanding at December 31, 2007.

Oglethorpe and GPC have entered into agreements providing for the purchase and subsequent joint operation of certain of GPC's and Oglethorpe's electric generating plants. The plant investments disclosed in the table below represent Oglethorpe's undivided interest in each co-owned plant, and each co-owner is responsible for providing its own financing. A summary of Oglethorpe's plant investments and related accumulated depreciation as of December 31, 2008 is as follows:

Plant				Investment		Accumulated Depreciation

				(dollars in thousands)
In-service
	Owned property
		Vogtle Units No. 1 & No. 2
			(Nuclear—30% ownership)	$	2,736,694	$	(1,420,879	)
		Hatch Units No. 1 & No. 2
			(Nuclear—30% ownership)		588,157		(343,217	)
		Wansley Units No. 1 & No. 2
			(Fossil—30% ownership)		311,802		(110,684	)
		Scherer Unit No. 1
			(Fossil—60% ownership)		495,734		(253,818	)
		Rocky Mountain Units No. 1,
			No. 2 & No. 3
			(Hydro—75% ownership)		557,387		(150,350	)
		Talbot (Combustion Turbine—
			100% ownership)		279,696		(52,536	)
		Chattahoochee (Combined cycle—
			100% ownership)		299,117		(52,371	)
		Wansley (Combustion Turbine—
			30% ownership)		3,627		(2,677	)
		Transmission plant			70,777		(37,329	)
		Other			92,248		(48,326	)
Property under capital lease:
		Plant Doyle (Combustion Turbine—
			100% leasehold)		126,990		(71,108	)
		Scherer Unit No. 2 (Fossil—60%
			leasehold)		344,636		(210,659	)

Total in-service				$	5,906,865	$	(2,753,954	)

Construction work in progress
		Generation improvements		$	302,616
		Other			4,848

Total construction work in progress				$	307,464

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 statement of revenues and expenses.

Oglethorpe is currently participating in 30% of the development costs of Plant Vogtle nuclear Units No. 3 and No. 4 pursuant to the terms of a development agreement with GPC and the other co-owners of the two existing nuclear units at Plant Vogtle. As of December 31, 2008, the total capitalized costs to date were $38,899,000.

Oglethorpe's retirement plan is a contributory 401(k) that covers substantially all employees. An employee may contribute, subject to IRS limitations, up to 60% of their eligible annual compensation. Oglethorpe, at its discretion, may match the employee's contribution and has done so each year of the plan's existence. Oglethorpe's current policy is to match the employee's contribution as long as there is sufficient margin to do so. The match, which is calculated each pay period, currently can be equal to as much as three-quarters of the first 6% of an employee's eligible compensation, depending on the amount and timing of the employee's contribution. Oglethorpe's contributions to the matching feature of the plan were approximately $677,000 in 2008, $644,000 in 2007 and $630,000 in 2006. Effective 2007, Oglethorpe's contribution was 8% to the employer retirement contribution feature. Oglethorpe's contributions to the employer retirement contribution feature of the 401(k) plan were approximately $1,305,000 in 2008, $775,000 in 2007 and $758,000 in 2006.

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 $8,483,000 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 each of the NEIL policies, members are subject to retroactive assessments in proportion to their premiums if losses exceed the accumulated funds available to the insurer under the policy. The portion of the current maximum annual assessment for GPC that would be payable by Oglethorpe, based on ownership share, is limited to approximately $10,587,000.

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 $12,520,000,000 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 $117,500,000 per incident for each licensed reactor operated by it, but not more than $17,500,000 per reactor per incident to be paid in a calendar year. On the basis of its ownership interest in four nuclear reactors, Oglethorpe could be assessed a maximum of $141,000,000 per incident, but not more than $21,000,000 in any one year. Both the maximum assessment per reactor and the maximum yearly assessment are adjusted for inflation at least every five years. The next scheduled adjustment is due no later than October 29, 2013.

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

Claims resulting from terrorist acts are covered under both the ANI and NEIL policies (subject to normal policy limits). The aggregate, however, that NEIL will pay for all claims resulting from terrorist acts in any 12 month period is $3,200,000,000 plus such additional amounts NEIL can recover through reinsurance, indemnity, or other sources.

Oglethorpe has entered into two long-term power purchase agreements. In December 2008, the Morgan Stanley Incremental power purchase agreement expired. As of December 31, 2008, Oglethorpe's minimum purchase commitment under the remaining agreement, without regard to capacity reductions or adjustments for changes in costs, for the next five years and thereafter is as follows:

Oglethorpe's power purchases agreements amounted to approximately $84,458,000 in 2008, $89,244,000 in 2007 and $102,646,000 in 2006.

As of December 31, 2008, Oglethorpe's estimated minimum rental commitments for these operating leases over the next five years and thereafter are as follows:

Rental expenses totaled $5,157,000 in 2008, $5,299,000 in 2007 and $5,227,000 in 2006. The rental expenses for the leases are added to the cost of the fossil inventories.

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

An allowance authorizes a utility to emit one ton of sulfur dioxide 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 sulfur dioxide allowance program.

During 2008, 2007, and 2006, Oglethorpe sold sulfur dioxide allowances in excess of its needs to various parties and received $327,000, $394,000, and $39,529,000 million in proceeds from these sales, respectively. Oglethorpe offset $327,000, $394,000 and $29,300,000 of this income by reducing amounts collected from its Members during 2008, 2007 and 2006, respectively. The remaining $10,200,000 of income in 2006 was offset by amortizing $10,200,000 of deferred asset retirement obligations costs. As a result, there was no net change to net margin in 2006.

As of December 31, 2008 and 2007, 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 and replacement credit enhancement. See Note 2 for discussion of Rocky Mountain transactions.

The amount of the fair value of Oglethorpe's guarantee related to the PCBs assumed by GTC is immaterial due to the small amount of assumed principal outstanding and the high credit rating of GTC. Oglethorpe estimates that the current maximum aggregate amount of exposure it would have if it were required to purchase the equity interests of the six owner trusts under the Rocky Mountain Lease Arrangements is approximately $250,000,000. See Note 2 for discussion of Rocky Mountain transactions.

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.

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

In April 2007, the Sierra Club and the Coosa River Basin Initiative appealed two unsuccessful permit challenges involving operating permit renewals for Plants Scherer (co-owned by Oglethorpe), Bowen, Hammond and Branch to the U.S. Court of Appeals for the Eleventh Circuit. The remaining challenge in the appeal is that the permits for Scherer and Bowen do not include compliance schedules to bring the sources into compliance with Prevention of Significant Deterioration requirements. Oglethorpe filed a motion to intervene on behalf of EPA in the case and that motion was granted. Briefing on the case was completed in December 2007, and oral argument was heard on March 31, 2008. A decision in favor of EPA was issued by the Court on November 24, 2008. The time for appeals has run and this case is ended.

Oglethorpe had appealed Monroe County's assessment for years 2003 through 2007 and accrued the disputed additional taxes in the amount of $22.7 million, which it had not paid to the County. Pursuant to a Consent Agreement and Release, Monroe County agreed not to seek the payment of any additional taxes for 2003 through 2007, and Oglethorpe withdrew its appeals for those years. Accordingly, the accrual of $22.7 million for the disputed taxes was reversed.

In our opinion, the accompanying consolidated balance sheets, consolidated statements of capitalization and the related consolidated statements of revenues and expenses, patronage capital and membership fees and accumulated other comprehensive deficit and cash flows present fairly, in all material respects, the financial position of Oglethorpe Power Corporation and its subsidiaries (an Electric Membership Cooperative) at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008 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.

Our members 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 our members. Refunds of accumulated patronage capital to the individual consumers may be made from time to time subject to limitations contained in mortgages between our members and the Rural Utilities Service or loan documents with other lenders. The Rural Utilities Service mortgage generally prohibits such distributions unless, after any such distribution, the member's total equity will equal at least 30% of its total assets, except that distributions may be made of up to 25% of the margins and patronage capital received by the member in the preceding year provided that equity is at least 20%.

The following selected information on the individual members is intended to show, in the aggregate, the assets, liabilities, equity, revenues and margins of our members. Member assets, liabilities, equity, revenues and margins should not, however, be attributed to us. In addition, the revenues of our members are not pledged to us, but such revenues are received by the respective members and are the source from which moneys are derived by our members to pay for power and energy received from us. Revenues of our members are, however, pledged under their respective Rural Utilities Service mortgages or loan documents with other lenders.

The information contained in these tables was taken from Rural Utilities Service Financial and Statistical Reports (RUS Form 7) or similar reports prepared for other lenders or provided directly by a member. This information has not been independently verified by the Rural Utilities Service, any lender or us. The "Total" columns for all these years were not supplied or compiled by the Rural Utilities Service, any lender or our members. The "Total" column in each table is for informational purposes only, inasmuch as each member operates independently and is not responsible for the obligations of other members (except as provided in the wholesale power contracts; see "OUR BUSINESS"). In addition, the Times Interest Earned Ratios (TIER) and Equity Ratios were calculated by us from information obtained from each member's RUS Form 7 or other financial information provided to us, but the calculations were not independently verified by our members. No adjustments were made by us in calculating these ratios for items such as debt refinancings that are not shown on the RUS Form 7 or were not reflected in such other financial information provided to us. For the calendar years 2006, 2007 and 2008, the information on the individual members is presented in the succeeding tables as follows: Table 1, selected statistics; Table 2, average number of consumers served; Table 3, annual megawatt-hour sales by consumer class; Table 4, annual revenues by consumer class; Table 5, summary of operating results; and Table 6, condensed balance sheet information.

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

	Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb(1)		Colquitt		Coweta- Fayette		Diverse

2008
Avg. Monthly Residential Rev.($)		115.77		111.41		117.66		126.67		122.65		144.90		119.47		112.45		135.08		136.42
Avg. Monthly Residential kWh		1,171		1,171		1,260		1,194		1,303		1,326		1,168		1,272		1,251		1,402
Avg. Residential Rev.(cents per kWh)		9.89		9.51		9.34		10.61		9.41		10.93		10.23		8.84		10.80		9.73
Times Interest Earned Ratio(2)		1.41		1.41		1.91		1.68		1.30		1.79		0.99		1.60		2.08		1.63
Equity/Assets(2)		64%		41%		37%		32%		34%		31%		30%		43%		29%		44%
Equity/Total Capitalization(2)		71%		52%		47%		39%		38%		34%		40%		51%		36%		50%
2007
Avg. Monthly Residential Rev.($)		111.78		113.47		115.01		120.85		115.29		138.10		116.96		113.63		126.79		122.73
Avg. Monthly Residential kWh		1,167		1,172		1,257		1,189		1,304		1,317		1,267		1,300		1,277		1,396
Avg. Residential Rev.(cents per kWh)		9.58		9.68		9.15		10.16		8.84		10.49		9.23		8.74		9.93		8.79
Times Interest Earned Ratio(2)		1.73		3.27		1.80		2.19		1.86		1.46		1.22		2.61		1.86		1.26
Equity/Assets(2)		65%		42%		37%		33%		34%		31%		31%		44%		27%		50%
Equity/Total Capitalization(2)		72%		54%		43%		39%		37%		40%		41%		46%		32%		58%
2006
Avg. Monthly Residential Rev.($)		111.40		111.85		111.86		114.44		115.91		132.86		110.16		109.78		120.98		124.71
Avg. Monthly Residential kWh		1,190		1,163		1,275		1,138		1,312		1,357		1,202		1,280		1,258		1,397
Avg. Residential Rev.(cents per kWh)		9.36		9.62		8.78		10.05		8.84		9.79		9.17		8.58		9.62		8.92
Times Interest Earned Ratio(2)		3.02		3.68		1.98		3.17		2.27		1.87		1.55		3.01		1.86		3.11
Equity/Assets(2)		64%		41%		38%		35%		36%		33%		33%		45%		26%		56%
Equity/Total Capitalization(2)		73%		50%		44%		40%		40%		39%		43%		54%		30%		62%
	Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2008
Avg. Monthly Residential Rev.($)		147.41		124.66		110.86		134.65		137.14		117.95		123.33		126.93		141.89		120.52
Avg. Monthly Residential kWh		1,328		1,326		1,058		1,154		1,279		1,289		1,031		1,250		1,275		1,202
Avg. Residential Rev.(cents per kWh)		11.10		9.40		10.48		11.66		10.72		9.15		11.97		10.15		11.13		10.03
Times Interest Earned Ratio(2)		1.72		2.33		2.17		1.40		1.26		2.13		0.98		2.44		1.95		1.99
Equity/Assets(2)		36%		53%		40%		31%		31%		46%		25%		37%		34%		34%
Equity/Total Capitalization(2)		45%		60%		46%		38%		34%		49%		29%		50%		39%		44%
2007
Avg. Monthly Residential Rev.($)		136.50		120.36		107.50		125.31		136.65		114.61		122.44		121.94		126.13		120.19
Avg. Monthly Residential kWh		1,336		1,331		1,051		1,141		1,290		1,275		1,036		1,282		1,309		1,213
Avg. Residential Rev.(cents per kWh)		10.22		9.04		10.23		10.98		10.60		8.99		11.82		9.51		9.64		9.91
Times Interest Earned Ratio(2)		1.45		1.86		2.15		1.63		2.08		1.96		1.53		2.11		1.95		2.67
Equity/Assets(2)		37%		54%		38%		32%		32%		46%		26%		35%		28%		33%
Equity/Total Capitalization(2)		43%		64%		45%		37%		35%		50%		30%		46%		31%		42%
2006
Avg. Monthly Residential Rev.($)		134.52		119.47		103.64		117.18		127.21		112.82		116.62		113.99		122.86		121.68
Avg. Monthly Residential kWh		1,334		1,319		1,073		1,137		1,296		1,295		1,025		1,297		1,305		1,230
Avg. Residential Rev.(cents per kWh)		10.09		9.06		9.66		10.31		9.81		8.71		11.38		8.79		9.41		9.90
Times Interest Earned Ratio(2)		1.50		2.98		1.49		1.56		1.60		2.42		1.79		2.43		1.55		2.03
Equity/Assets(2)		41%		57%		40%		33%		33%		46%		29%		36%		34%		33%
Equity/Total Capitalization(2)		45%		68%		44%		40%		39%		51%		33%		50%		40%		40%

	Excelsior		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee

2008
Avg. Monthly Residential Rev.($)		114.53		127.67		103.46		106.64		112.60		137.93		114.52		117.47		112.38
Avg. Monthly Residential kWh		1,335		1,185		1,188		1,078		1,125		1,151		1,277		1,201		1,063
Avg. Residential Rev.(cents per kWh)		8.58		10.78		8.71		9.89		10.01		11.98		8.97		9.78		10.57
Times Interest Earned Ratio(2)		2.06		3.23		1.74		1.45		2.13		1.54		1.82		1.93		1.48
Equity/Assets(2)		55%		48%		37%		33%		41%		32%		35%		40%		31%
Equity/Total Capitalization(2)		61%		60%		42%		38%		48%		34%		41%		46%		35%
2007
Avg. Monthly Residential Rev.($)		106.21		127.66		103.27		105.22		111.64		133.97		111.22		115.86		108.32
Avg. Monthly Residential kWh		1,339		1,207		1,210		1,055		1,123		1,187		1,277		1,198		1,065
Avg. Residential Rev.(cents per kWh)		7.93		10.58		8.54		9.97		9.94		11.29		8.71		9.67		10.17
Times Interest Earned Ratio(2)		2.20		2.05		2.48		1.39		2.48		1.40		2.01		1.85		1.26
Equity/Assets(2)		53%		48%		37%		33%		40%		32%		34%		40%		32%
Equity/Total Capitalization(2)		60%		58%		42%		37%		46%		38%		41%		47%		36%
2006
Avg. Monthly Residential Rev.($)		111.90		124.93		100.08		99.92		105.32		128.51		107.94		112.39		107.08
Avg. Monthly Residential kWh		1,352		1,192		1,187		1,048		1,103		1,184		1,263		1,201		1,076
Avg. Residential Rev.(cents per kWh)		8.27		10.48		8.43		9.54		9.55		10.85		8.54		9.36		9.95
Times Interest Earned Ratio(2)		2.39		2.55		3.08		1.59		2.19		1.98		2.18		1.82		1.27
Equity/Assets(2)		50%		49%		38%		33%		42%		34%		32%		39%		32%
Equity/Total Capitalization(2)		58%		59%		44%		38%		48%		37%		39%		46%		37%
	Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington		MEMBER TOTAL
2008
Avg. Monthly Residential Rev.($)		119.96		137.04		143.07		108.08		127.86		101.13		111.87		120.02		120.99
Avg. Monthly Residential kWh		1,334		1,307		1,447		957		1,224		1,120		1,329		1,098		1,240
Avg. Residential Rev.(cents per kWh)		9.00		10.5		9.89		11.3		10.45		9.03		8.42		10.93		9.76
Times Interest Earned Ratio(2)		2.37		1.54		2.37		1.57		1.51		1.84		3.65		1.48		1.77(3)
Equity/Assets(2)		38%		38%		43%		38%		30%		48%		38%		47%		36%(3)
Equity/Total Capitalization(2)		49%		45%		46%		42%		33%		55%		46%		50%		43%(3)
2007
Avg. Monthly Residential Rev.($)		117.89		126.09		138.01		106.14		119.86		98.52		111.64		116.00		116.79
Avg. Monthly Residential kWh		1,379		1,285		1,444		1,001		1,223		1,100		1,344		1,088		1,261
Avg. Residential Rev.(cents per kWh)		8.55		9.82		9.56		10.60		9.80		8.95		8.30		10.66		9.26
Times Interest Earned Ratio(2)		2.53		2.01		2.39		1.52		1.58		2.40		4.21		2.00		2.00(3)
Equity/Assets(2)		39%		39%		44%		39%		31%		46%		39%		49%		36%(3)
Equity/Total Capitalization(2)		49%		45%		48%		42%		36%		53%		46%		53%		43%(3)
2006
Avg. Monthly Residential Rev.($)		115.29		119.56		134.12		112.57		118.52		95.44		112.38		114.86		113.32
Avg. Monthly Residential kWh		1,360		1,280		1,453		1,062		1,229		1,103		1,322		1,114		1,247
Avg. Residential Rev.(cents per kWh)		8.48		9.34		9.23		10.60		9.64		8.66		8.50		10.31		9.09
Times Interest Earned Ratio(2)		2.88		2.76		2.26		1.35		2.16		2.95		5.70		1.86		2.28(3)
Equity/Assets(2)		41%		41%		44%		39%		32%		48%		38%		49%		37%(3)
Equity/Total Capitalization(2)		51%		47%		49%		43%		35%		55%		46%		52%		44%(3)

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

		Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb(1)		Colquitt		Coweta- Fayette		Diverse

2008
Residential Service			17,850		41,487		18,813		46,659		45,417		14,102		173,411		55,764		68,283		24,658
Commercial & Industrial			1,773		4,374		296		2,463		4,488		1,890		14,842		3,149		4,794		3,501
Other			116		11		262		377		150		118		5,349		1,926		633		165

	Total Consumers Served		19,739		45,872		19,371		49,499		50,055		16,110		193,602		60,839		73,710		28,324

2007
Residential Service			17,694		40,570		18,227		46,572		44,699		13,791		173,213		54,716		67,785		24,324
Commercial & Industrial			1,748		4,533		286		2,420		4,403		1,895		14,486		3,039		4,628		3,383
Other			113		10		251		372		116		119		5,807		1,831		592		160

	Total Consumers Served		19,555		45,113		18,764		49,364		49,218		15,805		193,506		59,586		73,005		27,867

2006
Residential Service			17,505		38,871		18,004		46,955		42,643		13,386		172,078		53,347		66,559		23,875
Commercial & Industrial			1,695		4,449		274		2,364		4,374		1,732		13,821		3,026		4,419		3,259
Other			107		26		247		368		98		119		6,193		1,755		533		161

	Total Consumers Served		19,307		43,346		18,525		49,687		47,115		15,237		192,092		58,128		71,511		27,294

		Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2008
Residential Service			5,019		21,425		10,693		11,344		31,716		14,950		16,629		48,158		132,017		7,468
Commercial & Industrial			1,720		1,202		658		1,164		2,288		574		2,093		2,548		14,463		337
Other			712		1,907		414		137		375		627		0		1,809		2,395		202

	Total Consumers Served		7,451		24,534		11,765		12,645		34,379		16,151		18,722		52,515		148,875		8,007

2007
Residential Service			4,972		21,306		10,595		11,355		31,162		14,871		16,647		47,702		129,414		7,361
Commercial & Industrial			1,689		1,188		657		1,099		2,249		561		2,004		2,541		13,796		317
Other			669		1,683		398		135		357		587		0		1,703		2,709		191

	Total Consumers Served		7,330		24,177		11,650		12,589		33,768		16,019		18,651		51,946		145,919		7,869

2006
Residential Service			4,914		21,082		10,467		11,334		30,145		14,799		16,602		46,996		124,236		7,132
Commercial & Industrial			1,665		1,154		657		1,043		2,085		560		1,867		2,531		12,933		325
Other			633		1,594		396		134		351		562		0		1,611		3,142		178

	Total Consumers Served		7,212		23,830		11,520		12,511		32,581		15,921		18,469		51,138		140,311		7,635

		Excelsior		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee

2008
Residential Service			19,701		17,636		109,379		31,356		28,725		10,661		185,196		30,901		10,541
Commercial & Industrial			1,413		447		9,703		2,429		6,721		133		15,213		1,562		121
Other			244		478		1,329		5		5		871		4,234		227		324

	Total Consumers Served		21,358		18,561		120,411		33,790		35,451		11,665		204,643		32,690		10,986

2007
Residential Service			19,235		17,617		107,751		31,021		28,748		10,608		183,960		30,724		10,431
Commercial & Industrial			1,403		441		9,765		2,412		6,569		118		14,557		1,544		115
Other			236		460		1,254		5		4		832		4,055		204		313

	Total Consumers Served		20,874		18,518		118,770		33,438		35,321		11,558		202,572		32,472		10,859

2006
Residential Service			18,908		17,278		102,462		30,290		28,548		10,519		178,339		30,374		10,254
Commercial & Industrial			1,361		437		9,688		2,331		6,380		119		13,827		1,514		112
Other			228		448		1,136		5		4		808		3,812		195		304

	Total Consumers Served		20,497		18,163		113,286		32,626		34,932		11,446		195,978		32,083		10,670

		Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington		MEMBER TOTAL
2008
Residential Service			86,440		17,699		14,660		14,007		19,086		8,444		108,147		14,685		1,533,127
Commercial & Industrial			5,385		1,052		4,636		555		1,855		794		7,454		584		128,674
Other			122		16		304		587		0		119		1,733		38		28,321

	Total Consumers Served		91,947		18,767		19,600		15,149		20,941		9,357		117,334		15,307		1,690,122

2007
Residential Service			85,862		17,556		14,536		13,980		18,776		8,400		107,457		14,589		1,518,227
Commercial & Industrial			5,207		1,042		4,586		547		1,775		824		7,253		561		125,641
Other			0		13		251		513		0		119		1,712		33		27,807

	Total Consumers Served		91,069		18,611		19,373		15,040		20,551		9,343		116,422		15,183		1,671,675

2006
Residential Service			83,750		17,235		14,340		12,895		18,268		8,300		105,196		14,493		1,482,378
Commercial & Industrial			4,657		1,012		4,486		535		1,697		862		6,975		539		120,765
Other			0		11		233		487		0		114		1,650		28		27,672

	Total Consumers Served		88,407		18,258		19,059		13,917		19,965		9,276		113,821		15,060		1,630,815

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

		Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb(1)		Colquitt		Coweta- Fayette		Diverse

2008
Residential Service			250,736		583,066		284,473		668,276		710,366		224,366		2,431,224		851,161		1,025,211		414,761
Commercial & Industrial			97,461		107,534		99,180		380,089		356,156		180,387		1,223,717		240,128		407,822		110,308
Other			3,775		168		4,996		6,881		2,034		2,140		232,713		72,292		11,550		8,465

	Total MWh Sales		351,972		690,769		388,649		1,055,247		1,068,556		406,893		3,887,654		1,163,581		1,444,582		533,534

2007
Residential Service			247,865		570,469		274,936		664,485		699,360		217,871		2,632,962		853,513		1,038,384		407,589
Commercial & Industrial			531,113		107,423		99,655		390,186		347,904		168,440		1,254,909		282,712		411,563		111,046
Other			4,640		155		5,605		7,195		1,551		2,155		215,651		79,543		11,217		6,092

	Total MWh Sales		783,617		678,047		380,195		1,061,867		1,048,814		388,465		4,103,522		1,215,768		1,461,164		524,727

2006
Residential Service			249,949		542,587		275,357		641,436		671,220		218,003		2,482,055		819,200		1,004,884		400,327
Commercial & Industrial			541,018		101,716		96,104		382,755		322,434		147,069		1,276,289		840,218		385,437		108,431
Other			4,313		296		4,691		6,857		1,262		2,200		235,807		67,239		11,089		6,072

	Total MWh Sales		795,280		644,598		376,152		1,031,048		994,916		367,272		3,994,151		1,726,657		1,401,410		514,830

		Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2008
Residential Service			79,957		340,840		135,739		157,157		486,865		231,195		205,658		722,399		2,019,688		107,713
Commercial & Industrial			39,233		72,067		46,427		126,936		55,922		18,656		51,688		274,837		1,014,927		48,111
Other			11,303		53,897		6,360		3,359		17,534		13,550		0		32,188		29,005		6,998

	Total MWh Sales		130,492		466,804		188,527		287,452		560,320		263,402		257,346		1,029,423		3,063,620		162,823

2007
Residential Service			79,725		340,293		133,563		155,474		482,283		227,586		206,888		733,749		2,032,865		107,115
Commercial & Industrial			40,988		79,872		46,513		108,599		58,148		17,582		53,333		258,089		995,115		49,145
Other			10,252		58,214		6,150		3,062		17,639		12,155		0		32,842		28,875		7,004

	Total MWh Sales		130,964		478,380		186,225		267,135		558,070		257,323		260,222		1,024,680		3,056,855		163,265

2006
Residential Service			78,640		333,725		134,816		154,620		468,886		229,974		204,207		731,477		1,946,279		105,234
Commercial & Industrial			38,187		71,511		44,833		108,125		69,664		18,163		47,657		256,513		933,893		48,597
Other			9,240		42,838		5,676		2,833		17,188		9,168		0		29,652		28,142		6,757

	Total MWh Sales		126,067		448,075		185,326		265,578		555,738		257,306		251,863		1,017,642		2,908,313		160,588

		Excelsior		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee

2008
Residential Service			315,649		250,682		1,559,437		405,579		387,904		147,233		2,838,692		445,444		134,423
Commercial & Industrial			71,638		30,847		1,075,592		95,522		183,084		20,981		1,808,948		108,470		49,488
Other			4,411		14,092		13,695		82		527		15,779		275,252		11,336		4,362

	Total MWh Sales		391,698		295,621		2,648,724		501,183		571,515		183,994		4,922,893		565,250		188,273

2007
Residential Service			308,975		255,097		1,564,147		392,769		387,394		151,094		2,817,923		441,694		133,282
Commercial & Industrial			70,809		33,474		1,102,039		92,734		182,865		18,881		1,809,952		114,995		49,342
Other			4,615		16,098		12,581		82		428		19,517		262,077		9,690		5,292

	Total MWh Sales		384,398		304,669		2,678,767		485,585		570,686		189,493		4,889,952		566,380		187,916

2006
Residential Service			306,849		247,188		1,459,309		380,781		377,762		149,457		2,703,569		437,716		132,412
Commercial & Industrial			72,219		31,278		1,016,657		88,492		169,602		19,009		1,721,703		112,658		48,072
Other			3,978		12,944		11,101		81		496		18,060		248,064		7,205		5,370

	Total MWh Sales		383,046		291,410		2,487,067		469,353		547,860		186,527		4,673,335		557,579		185,855

		Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington		MEMBER TOTAL
2008
Residential Service			1,383,269		277,612		254,513		160,841		280,237		113,513		1,725,123		193,572		22,804,575
Commercial & Industrial			467,500		48,092		90,598		24,654		90,601		15,590		643,148		192,189		9,968,531
Other			1,319		5,770		17,693		28,769		0		2,375		79,801		1,746		996,217

	Total MWh Sales		1,852,089		331,474		362,803		214,264		370,838		131,478		2,448,073		387,507		33,769,323

2007
Residential Service			1,420,413		270,629		251,885		167,922		275,539		110,903		1,733,625		190,429		22,980,695
Commercial & Industrial			414,132		51,249		92,002		50,818		88,057		16,603		651,638		202,022		10,453,947
Other			0		4,613		17,102		6,134		0		2,418		80,725		1,522		952,892

	Total MWh Sales		1,834,544		326,491		360,989		224,875		363,595		129,925		2,465,988		393,974		34,387,534

2006
Residential Service			1,366,927		264,784		250,009		164,369		269,484		109,818		1,669,374		193,793		22,176,475
Commercial & Industrial			388,388		48,591		85,940		28,240		86,095		16,983		623,453		204,012		10,600,007
Other			0		4,493		14,324		21,816		0		2,328		79,122		1,169		921,872

	Total MWh Sales		1,755,315		317,868		350,272		214,425		355,579		129,129		2,371,949		398,975		33,698,354

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

		Altamaha			Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb(1)		Colquitt		Coweta- Fayette			Diverse

2008
Residential Service		$	24,797,886		$	55,467,194	$	26,561,661	$	70,921,260	$	66,846,610	$	24,520,853	$	248,607,918	$	75,246,221	$	110,686,730		$	40,365,675
Commercial & Industrial			35,313,760		$	10,826,809		7,785,466	$	28,514,805		29,008,815		11,941,889	$	101,424,938		18,959,552		35,733,895			10,661,620
Other			313,123		$	27,194		541,233	$	788,264		302,734		274,854	$	23,342,175		6,272,170		1,566,936			838,965

	Total Electric Sales	$	60,424,769		$	66,321,197	$	34,888,360	$	100,224,329	$	96,158,159	$	36,737,596	$	373,375,031	$	100,477,943	$	147,987,561		$	51,866,260
Other Operating Revenue			697,480			1,190,585		4,473,949		5,511,933		3,287,129		852,567		8,109,454		6,626,323		4,680,363			2,539,726

	Total Operating Revenue	$	61,122,249		$	67,511,782	$	39,362,309	$	105,736,262	$	99,445,288	$	37,590,163	$	381,484,485	$	107,104,266	$	152,667,924		$	54,405,986

2007
Residential Service		$	23,734,524		$	55,241,969	$	25,155,044	$	67,541,353	$	61,842,253	$	22,853,709	$	243,110,043	$	74,608,516	$	103,133,209		$	35,824,377
Commercial & Industrial			31,496,353			10,821,939		7,635,758		25,992,003		25,600,961		10,605,971	$	93,924,956		20,194,391		33,197,808			9,671,620
Other			351,161			25,039		573,781		785,895		234,875		269,229	$	21,884,941		6,747,077		1,445,588			628,362

	Total Electric Sales	$	55,582,038		$	66,088,947	$	33,364,583	$	94,319,251	$	87,678,089	$	33,728,909	$	358,919,940	$	101,549,984	$	137,776,605		$	46,124,359
Other Operating Revenue			637,049			3,482,949		3,944,376		5,590,330		3,105,401		786,346		8,445,746		4,584,350		4,317,562			2,294,228

	Total Operating Revenue	$	56,219,087		$	69,571,896	$	37,308,959	$	99,909,581	$	90,783,490	$	34,515,255	$	367,365,686	$	106,134,334	$	142,094,167		$	48,418,587

2006
Residential Service		$	23,400,436		$	52,171,649	$	24,166,244	$	64,481,647	$	59,314,810	$	21,341,000	$	227,482,468	$	70,274,490	$	96,631,471		$	35,728,529
Commercial & Industrial			37,849,671			10,119,511		7,165,437		25,210,357		23,057,335		8,994,864		88,300,171		36,835,229		30,312,743			9,399,848
Other			318,051			58,447		489,378		751,231		166,678		263,950		20,139,030		5,667,632		1,212,062			628,782

	Total Electric Sales	$	61,568,158		$	62,349,607	$	31,821,059	$	90,443,235	$	82,538,823	$	30,599,814	$	335,921,669	$	112,777,351	$	128,156,276		$	45,757,159
Other Operating Revenue			639,808			1,788,406		3,980,912		5,279,152		3,255,768		702,442		8,403,878		4,749,188		(401,179	)		2,303,550

	Total Operating Revenue	$	62,207,966		$	64,138,013	$	35,801,971	$	95,722,387	$	85,794,591	$	31,302,256	$	344,325,547	$	117,526,539	$	127,755,097		$	48,060,709

		Middle Georgia			Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee			Slash Pine
2008
Residential Service		$	8,878,502		$	32,049,621	$	14,225,432	$	18,330,104	$	52,194,681	$	21,159,693	$	24,610,958	$	73,352,974	$	224,784,969		$	10,800,263
Commercial & Industrial		$	4,605,196		$	6,687,307		4,295,045		8,054,265		5,478,980		1,516,821	$	5,754,781	$	20,581,282	$	93,027,523		$	3,705,460
Other		$	1,731,438		$	5,240,905		809,186		359,832		1,462,266		1,338,982		0	$	3,455,383	$	4,674,028		$	639,933

	Total Electric Sales	$	15,215,136		$	43,977,833	$	19,329,663	$	26,744,201	$	59,135,927	$	24,015,496	$	30,365,739	$	97,389,639	$	322,486,520		$	15,145,656
Other Operating Revenue			26,538			1,713,926		771,221		713,072		1,309,246		1,145,342		179,957		4,706,206		13,606,008			248,296

	Total Operating Revenue	$	15,241,674		$	45,691,759	$	20,100,884	$	27,457,273	$	60,445,173	$	25,160,838	$	30,545,696	$	102,095,845	$	336,092,528		$	15,393,952

2007
Residential Service		$	8,144,176		$	30,771,985	$	13,667,024	$	17,075,264	$	51,098,734	$	20,452,254	$	24,459,368	$	69,803,172	$	195,871,465		$	10,616,813
Commercial & Industrial			4,330,504		$	6,513,987		3,788,741		7,061,573		5,851,185		1,381,813	$	6,049,650	$	18,950,084		80,844,678			3,707,919
Other			1,508,800		$	5,214,846		734,389		317,565		1,510,847		1,170,198		0	$	3,308,818		4,148,473			628,488

	Total Electric Sales	$	13,983,480		$	42,500,818	$	18,190,154	$	24,454,402	$	58,460,766	$	23,004,265	$	30,509,018	$	92,062,074	$	280,864,616		$	14,953,220
Other Operating Revenue			(56,940	)		1,704,679		659,475		635,571		989,600		1,090,880		208,005		5,871,946		10,269,909			264,012

	Total Operating Revenue	$	13,926,540		$	44,205,497	$	18,849,629	$	25,089,973	$	59,450,366	$	24,095,145	$	30,717,023	$	97,934,020	$	291,134,525		$	15,217,232

2006
Residential Service		$	7,932,313		$	30,223,149	$	13,018,001	$	15,936,513	$	46,018,140	$	20,036,173	$	23,232,937	$	64,286,473	$	183,160,064		$	10,413,924
Commercial & Industrial			4,005,291			6,064,635		3,334,858		6,618,726		5,929,173		1,379,014		5,219,760		15,486,095		73,988,929			3,649,217
Other			1,350,483			4,015,202		676,754		279,266		1,362,107		895,083		0		2,852,871		3,993,434			595,752

	Total Electric Sales	$	13,288,087		$	40,302,986	$	17,029,613	$	22,834,505	$	53,309,420	$	22,310,270	$	28,452,697	$	82,625,439	$	261,142,427		$	14,658,893
Other Operating Revenue			(304,215	)		121,459		600,974		794,869		923,536		986,467		262,016		6,801,407		1,443,391			174,825

	Total Operating Revenue	$	12,983,872		$	40,424,445	$	17,630,587	$	23,629,374	$	54,232,956	$	23,296,737	$	28,714,713	$	89,426,846	$	262,585,818		$	14,833,718

		Excelsior		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee

2008
Residential Service		$	27,077,091	$	27,019,905	$	135,794,782	$	40,126,898	$	38,812,082	$	17,645,607	$	254,512,451	$	43,560,868	$	14,214,966
Commercial & Industrial		$	6,235,782	$	2,843,957		77,821,290		8,416,381		17,182,330	$	2,192,111	$	139,677,443		8,472,330		3,446,368
Other		$	483,197	$	1,481,011		2,267,363		7,164		40,037	$	2,037,871	$	26,309,546		1,091,808		548,573

	Total Electric Sales	$	33,796,070	$	31,344,873	$	215,883,435	$	48,550,443	$	56,034,449	$	21,875,589	$	420,499,440	$	53,125,006	$	18,209,907
Other Operating Revenue			1,441,733		1,189,260		8,041,587		1,748,225		2,487,785		612,504	$	21,057,054		2,212,086		717,058

	Total Operating Revenue	$	35,237,803	$	32,534,133	$	223,925,022	$	50,298,668	$	58,522,234	$	22,488,093	$	441,556,494	$	55,337,092	$	18,926,965

2007
Residential Service		$	24,515,997	$	26,987,246	$	133,532,470	$	39,167,769	$	38,511,658	$	17,053,730	$	245,516,448	$	42,716,753	$	13,558,990
Commercial & Industrial			5,590,272		2,858,892		75,737,409		8,087,900	$	16,777,072		1,819,163		132,445,332		8,358,480		3,234,617
Other			466,136		1,628,784		2,102,419		7,153	$	32,645		2,380,076		24,442,829		964,420		605,504

	Total Electric Sales	$	30,572,405	$	31,474,922	$	211,372,298	$	47,262,822	$	55,321,375	$	21,252,969	$	402,404,609	$	52,039,653	$	17,399,111
Other Operating Revenue			2,140,302		1,345,894		7,532,810		1,658,658		2,254,934		615,347		19,121,666		2,280,988		535,358

	Total Operating Revenue	$	32,712,707	$	32,820,816	$	218,905,108	$	48,921,480	$	57,576,309	$	21,868,316	$	421,526,275	$	54,320,641	$	17,934,469

2006
Residential Service		$	25,390,500	$	25,902,845	$	123,055,050	$	36,318,100	$	36,081,128	$	16,221,618	$	231,000,777	$	40,965,294	$	13,175,616
Commercial & Industrial			5,676,466		2,733,626		68,439,240		7,650,997		15,317,143		1,730,723		123,034,176		7,800,968		3,085,001
Other			415,161		1,336,463		1,861,630		7,064		35,769		2,134,793		21,767,316		714,787		587,692

	Total Electric Sales	$	31,482,127	$	29,972,934	$	193,355,920	$	43,976,161	$	51,434,040	$	20,087,134	$	375,802,269	$	49,481,049	$	16,848,309
Other Operating Revenue			706,960		1,137,395		7,096,226		2,483,628		1,853,186		660,836		15,793,452		2,168,788		251,953

	Total Operating Revenue	$	32,189,087	$	31,110,329	$	200,452,146	$	46,459,789	$	53,287,226	$	20,747,970	$	391,595,721	$	51,649,837	$	17,100,262

		Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington		MEMBER TOTAL
2008
Residential Service		$	124,433,704	$	29,104,999	$	25,168,061	$	18,165,856	$	29,284,828	$	10,247,755	$	145,182,612	$	21,149,536	$	2,225,911,206
Commercial & Industrial		$	35,218,058		4,274,547		8,981,195		2,678,331		8,389,237		1,569,632	$	50,027,770		13,211,499		834,516,470
Other		$	245,842		510,205		1,848,802		3,491,374		0		270,963	$	8,614,993		152,830		103,381,180

	Total Electric Sales	$	159,897,604	$	33,889,751	$	35,998,058	$	24,335,561	$	37,674,065	$	12,088,350	$	203,825,375	$	34,513,865	$	3,163,808,856
Other Operating Revenue			8,016,832		1,065,193		882,953		754,531		1,045,366		528,756		11,979,332		908,243		127,077,819

	Total Operating Revenue	$	167,914,436	$	34,954,944	$	36,881,011	$	25,090,092	$	38,719,431	$	12,617,106	$	215,804,707	$	35,422,108	$	3,290,886,675

2007
Residential Service		$	121,466,111	$	26,563,448	$	24,072,612	$	17,806,709	$	27,006,581	$	9,931,225	$	143,952,627	$	20,308,496	$	2,127,674,122
Commercial & Industrial		$	30,422,232		4,067,397		8,770,928	$	2,683,274		7,474,287		1,580,197		48,729,480		13,177,388		779,436,214
Other			0		367,528		1,572,475	$	3,362,015		0		268,343		8,342,559		128,905		98,160,163

	Total Electric Sales	$	151,888,343	$	30,998,373	$	34,416,015	$	23,851,998	$	34,480,868	$	11,779,765	$	201,024,666	$	33,614,789	$	3,005,270,499
Other Operating Revenue			4,727,868		998,067		1,460,991	$	721,555		1,003,191		361,132		11,559,032		947,062		118,090,329

	Total Operating Revenue	$	156,616,211	$	31,996,440	$	35,877,006	$	24,573,553	$	35,484,059	$	12,140,897	$	212,583,698	$	34,561,851	$	3,123,360,828

2006
Residential Service		$	115,871,272	$	24,727,886	$	23,079,344	$	17,419,652	$	25,981,484	$	9,505,326	$	141,863,733	$	19,976,530	$	2,015,786,586
Commercial & Industrial			27,439,793		3,726,857		8,016,021		2,549,043		6,951,359		1,522,929		46,852,108		13,009,154		748,456,468
Other			0		323,084		1,319,310		2,500,397		0		243,431		7,880,393		87,538		86,931,021

	Total Electric Sales	$	143,311,065	$	28,777,827	$	32,414,675	$	22,469,092	$	32,932,843	$	11,271,686	$	196,596,234	$	33,073,222	$	2,851,174,075
Other Operating Revenue			3,500,354		929,157		919,732		726,366		976,217		406,592		11,188,634		1,121,963		94,428,093

	Total Operating Revenue	$	146,811,419	$	29,706,984	$	33,334,407	$	23,195,458	$	33,909,060	$	11,678,278	$	207,784,868	$	34,195,185	$	2,945,602,168

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

			Altamaha		Amicalola		Canoochee		Carroll		Central Georgia			Coastal		Cobb(1)			Colquitt		Coweta- Fayette			Diverse

2008
Operating Revenue & Patronage Capital			$	61,122,249	$	67,511,782	$	39,362,309	$	105,736,262	$	99,445,288		$	37,590,162	$	381,484,485		$	107,104,266	$	152,667,924		$	54,405,986
Depreciation and Amortization				2,474,566		5,376,630		3,253,129		7,168,008		4,999,053			1,990,864		19,229,359			5,619,971		8,025,200			4,607,600
Other Operating Expenses				57,766,090		59,240,152		31,627,274		91,149,141		89,418,823			32,522,111		337,442,151			96,530,049		133,462,274			46,756,004

	Electric Operating Margin		$	881,593	$	2,895,000	$	4,481,906	$	7,419,113	$	5,027,412		$	3,077,187	$	24,812,975		$	4,954,246	$	11,180,450		$	3,042,382
Other Income				1,136,753		885,594		897,811		1,512,845		1,495,642			612,565		3,707,931			1,678,343		4,991,185			991,603

	Gross Operating Margin		$	2,018,346	$	3,780,594	$	5,379,717	$	8,931,958	$	6,523,054		$	3,689,752	$	28,520,906		$	6,632,589	$	16,171,635		$	4,033,985

Interest on Long-term Debt				1,424,717		2,666,272		2,797,252		5,254,766		4,963,311			2,003,837		22,928,984			4,155,707		7,141,203			2,427,995
Other Deductions				5,293		23,241		28,778		79,340		85,359			95,451		5,732,558			0		1,292,133			82,089

		Net Margins	$	588,336	$	1,091,081	$	2,553,687	$	3,597,852	$	1,474,384		$	1,590,464	$	(140,636	)	$	2,476,882	$	7,738,299		$	1,523,901

2007
Operating Revenue & Patronage Capital			$	56,219,088	$	69,571,896	$	37,308,959	$	99,909,581	$	90,783,491		$	34,515,255	$	367,365,686		$	106,134,334	$	142,094,164		$	48,418,587
Depreciation and Amortization				2,387,458		5,207,085		2,918,782		6,588,681		4,741,645			1,808,217		18,149,321			5,262,275		7,539,419			4,491,285
Other Operating Expenses				52,729,201		56,664,392		30,567,013		83,798,464		79,047,671			30,440,504		329,679,177			93,070,746		124,027,198			42,594,151

	Electric Operating Margin		$	1,102,429	$	7,700,419	$	3,823,164	$	9,522,436	$	6,994,175		$	2,266,534	$	19,537,188		$	7,801,313	$	10,527,547		$	1,333,151
Other Income				1,060,147		703,895		1,129,657		2,142,884		1,621,376			556,381		11,701,199			2,198,130		4,139,035			1,259,149

	Gross Operating Margin		$	2,162,576	$	8,404,314	$	4,952,821	$	11,665,320	$	8,615,551		$	2,822,915	$	31,238,387		$	9,999,443	$	14,666,582		$	2,592,300

Interest on Long-term Debt				1,247,594		2,564,691		2,750,930		5,329,405		4,548,119			1,615,357		20,420,738			3,827,885		7,384,049			1,999,212
Other Deductions				7,438		11,979		4,542		1,476		155,682			459,632		6,407,765			0		915,955			75,860

		Net Margins	$	907,544	$	5,827,644	$	2,197,349	$	6,334,439	$	3,911,750		$	747,926	$	4,409,884		$	6,171,558	$	6,366,578		$	517,228

2006
Operating Revenue & Patronage Capital			$	62,207,968	$	64,138,013	$	35,801,971	$	95,722,387	$	85,794,591		$	31,302,256	$	344,325,547		$	117,526,539	$	127,755,098		$	48,060,709
Depreciation and Amortization				2,319,477		4,896,320		2,946,579		6,067,430		4,404,396			1,653,742		16,711,060			4,892,772		7,082,013			4,130,496
Other Operating Expenses				56,955,671		50,575,713		28,875,370		77,679,535		73,229,423			26,903,356		303,134,156			103,448,979		110,066,667			39,340,968

	Electric Operating Margin		$	2,932,820	$	8,665,980	$	3,980,022	$	11,975,422	$	8,160,772		$	2,745,158	$	24,480,331		$	9,184,788	$	10,606,418		$	4,589,245
Other Income				967,482		708,259		961,125		1,419,937		1,388,290			412,012		9,904,486			2,178,056		3,365,142			971,895

	Gross Operating Margin		$	3,900,302	$	9,374,239	$	4,941,147	$	13,395,359	$	9,549,062		$	3,157,170	$	34,384,817		$	11,362,844	$	13,971,560		$	5,561,140

Interest on Long-term Debt				1,288,127		2,545,642		2,498,262		4,229,434		4,177,453			1,641,603		18,595,285			3,775,225		6,817,889			1,786,755
Other Deductions				8,445		288		4,537		1,047		70,709			93,166		5,587,808			0		1,294,257			3,648

		Net Margins	$	2,603,730	$	6,828,309	$	2,438,348	$	9,164,878	$	5,300,900		$	1,422,401	$	10,201,724		$	7,587,619	$	5,859,414		$	3,770,737

			Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke			Planters		Rayle			Satilla		Sawnee			Slash Pine
2008
Operating Revenue & Patronage Capital			$	15,241,674	$	45,691,759	$	20,100,884	$	27,457,273	$	60,445,173		$	25,160,839	$	30,545,696		$	102,095,845	$	336,092,528		$	15,393,952
Depreciation and Amortization				923,679		3,100,209	$	1,171,129		1,645,446		4,056,471			1,677,783		2,305,401			4,611,524		12,187,916			667,956
Other Operating Expenses				13,201,596		38,944,395		16,935,310		23,565,625		52,089,870			21,489,736		26,567,470			89,589,980		300,951,014			13,606,779

	Electric Operating Margin		$	1,116,399	$	3,647,155	$	1,994,445	$	2,246,202	$	4,298,832		$	1,993,320	$	1,672,825		$	7,894,341	$	22,953,598		$	1,119,217
Other Income				474,444		777,146		316,005		539,576		749,218			611,014		457,846			1,431,038		6,882,505			294,920

	Gross Operating Margin		$	1,590,843	$	4,424,301	$	2,310,450	$	2,785,778	$	5,048,050		$	2,604,334	$	2,130,671		$	9,325,379	$	29,836,103		$	1,414,137

Interest on Long-term Debt				829,074		1,747,895	$	1,060,747		1,925,252		4,022,440			1,224,532		2,172,995			3,513,417		15,026,708			710,015
Other Deductions				162,862		357,819		10,124		84,998		(18,583	)		906		5,736			769,064		507,439			500

		Net Margins	$	598,907	$	2,318,587	$	1,239,579	$	775,528	$	1,044,193		$	1,378,896	$	(48,060	)	$	5,042,898	$	14,301,956		$	703,622

2007
Operating Revenue & Patronage Capital			$	13,926,540	$	44,205,497	$	18,849,629	$	25,089,973	$	59,450,365		$	24,095,145	$	30,717,023		$	97,934,020	$	291,134,525		$	15,217,231
Depreciation and Amortization				855,014		2,899,752		1,186,528		1,534,278		3,782,071			1,611,502		2,182,563			4,417,962		12,526,400			630,851
Other Operating Expenses				12,076,252		38,555,524		15,774,176		20,983,036		49,206,990			20,816,892		25,867,992			87,114,692		259,982,329			13,137,035

	Electric Operating Margin		$	995,274	$	2,750,221	$	1,888,925	$	2,572,659	$	6,461,304		$	1,666,751	$	2,666,468		$	6,401,366	$	18,625,796		$	1,449,345
Other Income				315,488		722,905		349,361		547,458		659,543			734,768		524,354			1,630,050		7,815,672			309,142

	Gross Operating Margin		$	1,310,762	$	3,473,126	$	2,238,286	$	3,120,117	$	7,120,847		$	2,401,519	$	3,190,822		$	8,031,416	$	26,441,468		$	1,758,487

Interest on Long-term Debt				828,024		1,699,231		1,038,742		1,872,393		3,171,549			1,226,130		2,065,680			3,305,665		13,467,421			658,437
Other Deductions				109,994		307,532		8,146		65,428		509,471			1,229		34,540			1,049,618		129,671			553

		Net Margins	$	372,744	$	1,466,363	$	1,191,398	$	1,182,296	$	3,439,827		$	1,174,160	$	1,090,602		$	3,676,133	$	12,844,376		$	1,099,497

2006
Operating Revenue & Patronage Capital			$	12,983,872	$	41,865,476	$	17,630,587	$	23,629,374	$	54,232,956		$	23,296,737	$	28,714,713		$	89,426,846	$	262,585,818		$	14,833,718
Depreciation and Amortization				867,371		2,756,193		1,120,950		1,439,092		3,495,668			1,533,823		2,029,802			3,907,140		11,453,467			601,254
Other Operating Expenses				11,163,683		35,351,153		15,236,133		19,921,234		46,261,194			19,630,752		23,726,618			78,971,999		233,777,644			12,369,824

	Electric Operating Margin		$	952,818	$	3,758,130	$	1,273,504	$	2,269,048	$	4,476,094		$	2,132,162	$	2,958,293		$	6,547,707	$	17,354,707		$	1,862,640
Other Income				256,487		733,506		287,519		542,448		798,337			543,910		472,792			1,574,928		(1,955,097	)		243,903

	Gross Operating Margin		$	1,209,305	$	4,491,636	$	1,561,023	$	2,811,496	$	5,274,431		$	2,676,072	$	3,431,085		$	8,122,635	$	15,399,610		$	2,106,543

Interest on Long-term Debt				788,987		1,345,987		1,034,290		1,722,077		3,219,368			1,107,369		1,888,948			2,830,640		9,857,170			633,270
Other Deductions				27,296		474,010		19,952		128,398		131,439			1,230		57,663			1,247,935		131,111			819,863

		Net Margins	$	393,022	$	2,671,639	$	506,781	$	961,021	$	1,923,624		$	1,567,473	$	1,484,474		$	4,044,060	$	5,411,329		$	653,410

			Excelsior		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee

2008
Operating Revenue & Patronage Capital			$	35,237,802	$	32,534,134	$	223,925,022	$	50,298,668	$	58,522,235	$	22,488,093	$	441,556,493	$	55,337,092	$	18,926,965
Depreciation and Amortization				1,784,850		2,265,076		11,010,622		4,460,079		4,032,013		2,139,119		23,538,665		3,898,349		1,266,929
Other Operating Expenses				31,639,303		26,557,714		197,018,650		42,397,747		48,604,579		17,903,271		389,791,765		46,719,180		15,979,700

	Electric Operating Margin		$	1,813,649	$	3,711,344	$	15,895,750	$	3,440,842	$	5,885,643	$	2,445,703	$	28,226,063	$	4,719,563	$	1,680,336
Other Income				1,063,189		535,863		2,402,610		796,547		1,186,690		443,831		9,105,312		1,254,452		131,957

	Gross Operating Margin		$	2,876,838	$	4,247,207	$	18,298,360	$	4,237,389	$	7,072,333	$	2,889,534	$	37,331,375	$	5,974,015	$	1,812,293

Interest on Long-term Debt				1,399,237		1,236,423		10,102,531		2,903,665		3,310,437		1,733,805		20,521,744		3,083,827		1,219,400
Other Deductions				0		253,599		679,601		15,230		5,471		213,021		10,679		24,880		9,996

		Net Margins	$	1,477,601	$	2,757,185	$	7,516,228	$	1,318,494	$	3,756,425	$	942,708	$	16,798,952	$	2,865,308	$	582,897

2007
Operating Revenue & Patronage Capital			$	32,712,706	$	32,820,816	$	218,905,109	$	48,921,480	$	57,576,309	$	21,868,316	$	421,526,276	$	54,320,644	$	17,934,469
Depreciation and Amortization				1,697,034		2,162,979		9,828,318		4,417,334		3,908,295		1,976,941		22,016,932		3,645,414		1,181,066
Other Operating Expenses				29,128,158		28,296,063		188,904,391		40,878,147		47,011,256		17,857,902		369,672,591		46,430,546		15,396,587

	Electric Operating Margin		$	1,887,514	$	2,361,774	$	20,172,400	$	3,625,999	$	6,656,758	$	2,033,473	$	29,836,753	$	4,244,684	$	1,356,816
Other Income				1,276,241		562,966		3,223,915		422,097		1,181,417		421,326		10,523,948		1,443,786		146,607

	Gross Operating Margin		$	3,163,755	$	2,924,740	$	23,396,315	$	4,048,096	$	7,838,175	$	2,454,799	$	40,360,701	$	5,688,470	$	1,503,423

Interest on Long-term Debt				1,439,087		1,293,646		9,412,113		2,812,518		3,162,234		1,593,158		20,066,945		3,060,090		1,185,033
Other Deductions				0		268,434		64,298		133,681		3,439		216,827		11,315		21,185		10,038

		Net Margins	$	1,724,668	$	1,362,660	$	13,919,904	$	1,101,897	$	4,672,502	$	644,814	$	20,282,441	$	2,607,195	$	308,352

2006
Operating Revenue & Patronage Capital			$	32,189,091	$	31,110,331	$	200,452,145	$	46,459,789	$	53,287,226	$	20,747,970	$	391,595,721	$	51,649,840	$	17,100,264
Depreciation and Amortization				1,621,074		2,043,677		9,095,176		3,870,837		3,611,560		1,809,520		20,184,484		3,344,343		1,122,175
Other Operating Expenses				28,594,603		25,996,712		167,069,779		38,500,606		44,324,947		16,289,566		339,630,669		43,864,329		14,527,049

	Electric Operating Margin		$	1,973,414	$	3,069,942	$	24,287,190	$	4,088,346	$	5,350,719	$	2,648,884	$	31,780,568	$	4,441,168	$	1,451,040
Other Income				1,376,559		320,110		3,227,982		466,177		1,052,540		361,926		10,470,700		1,383,901		108,711

	Gross Operating Margin		$	3,349,973	$	3,390,052	$	27,515,172	$	4,554,523	$	6,403,259	$	3,010,810	$	42,251,268	$	5,825,069	$	1,559,751

Interest on Long-term Debt				1,396,797		1,215,712		8,879,210		2,845,719		2,921,642		1,502,804		19,376,043		3,112,730		1,215,412
Other Deductions				9,266		292,148		152,210		24,242		3,659		30,591		17,666		170,742		10,248

		Net Margins	$	1,943,910	$	1,882,192	$	18,483,752	$	1,684,562	$	3,477,958	$	1,477,415	$	22,857,559	$	2,541,597	$	334,091

			Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri- County		Upson		Walton		Washington		MEMBER TOTAL
2008
Operating Revenue & Patronage Capital			$	167,914,436	$	34,954,944	$	36,881,011	$	25,090,092	$	38,719,433	$	12,617,103	$	215,804,707	$	35,422,107	$	3,290,886,673
Depreciation and Amortization				8,294,183		1,770,263		2,388,039		1,394,617		2,804,867		706,272		10,454,227		1,940,870		179,240,934
Other Operating Expenses				151,416,234		31,703,326		30,068,754		21,799,647		32,274,730		11,191,448		194,776,401		31,675,740		2,894,374,033

	Electric Operating Margin		$	8,204,019	$	1,481,355	$	4,424,218	$	1,895,828	$	3,639,836	$	719,383	$	10,574,079	$	1,805,497	$	217,271,706
Other Income				5,271,751		508,352		797,109		258,022		614,205		380,856		13,846,887		451,418		69,493,035

	Gross Operating Margin		$	13,475,770	$	1,989,707	$	5,221,327	$	2,153,850	$	4,254,041	$	1,100,239	$	24,420,966	$	2,256,915	$	286,764,741

Interest on Long-term Debt				5,628,225		1,290,784		2,184,040		1,317,674		2,766,483		589,745		6,509,618		1,519,910		155,314,667
Other Deductions				121,000		0		52,689		78,868		84,870		16,425		635,090		0		11,506,526

		Net Margins	$	7,726,545	$	698,923	$	2,984,598	$	757,308	$	1,402,688	$	494,069	$	17,276,258	$	737,005	$	119,943,548

2007
Operating Revenue & Patronage Capital			$	156,616,211	$	31,996,440	$	35,877,006	$	24,573,553	$	35,484,059	$	12,140,896	$	212,583,698	$	34,561,850	$	3,123,360,827
Depreciation and Amortization				7,529,727		1,622,224		2,171,673		1,318,772		2,547,761		685,034		9,680,728		1,863,834		168,975,155
Other Operating Expenses				138,895,981		28,718,051		29,686,946		21,565,274		29,437,637		10,696,900		190,961,740		30,207,164		2,729,878,769

	Electric Operating Margin		$	10,190,503	$	1,656,165	$	4,018,387	$	1,689,507	$	3,498,661	$	758,962	$	11,941,230	$	2,490,852	$	224,506,903
Other Income				2,953,342		685,365		929,373		360,824		544,801		621,840		9,780,798		527,815		75,727,055

	Gross Operating Margin		$	13,143,845	$	2,341,530	$	4,947,760	$	2,050,331	$	4,043,462	$	1,380,802	$	21,722,028	$	3,018,667	$	300,233,958

Interest on Long-term Debt				5,177,679		1,167,244		2,052,523		1,295,258		2,495,760		569,917		5,013,107		1,511,947		144,329,511
Other Deductions				22,853		0		47,647		80,080		103,414		15,652		630,867		0		11,886,241

		Net Margins	$	7,943,313	$	1,174,286	$	2,847,590	$	674,993	$	1,444,288	$	795,233	$	16,078,054	$	1,506,720	$	144,018,206

2006
Operating Revenue & Patronage Capital			$	146,811,420	$	29,706,984	$	33,334,406	$	23,195,458	$	33,909,056	$	11,678,278	$	207,784,869	$	34,195,184	$	2,947,043,208
Depreciation and Amortization				6,893,925		1,592,101		2,013,126		1,261,442		2,256,003		644,906		9,108,183		1,753,975		156,535,552
Other Operating Expenses				128,530,306		25,557,545		27,667,062		20,493,069		27,109,876		10,064,630		179,984,669		30,093,596		2,534,919,085

	Electric Operating Margin		$	11,387,189	$	2,557,338	$	3,654,218	$	1,440,947	$	4,543,177	$	968,742	$	18,692,017	$	2,347,613	$	255,588,571
Other Income				2,422,659		769,986		709,104		398,878		535,301		511,767		6,412,517		519,583		56,823,818

	Gross Operating Margin		$	13,809,848	$	3,327,324	$	4,363,322	$	1,839,825	$	5,078,478	$	1,480,509	$	25,104,534	$	2,867,196	$	312,412,389

Interest on Long-term Debt				4,782,878		1,207,447		1,914,441		1,248,321		2,271,253		496,496		4,307,365		1,542,211		132,020,262
Other Deductions				35,877		0		39,573		149,645		165,106		15,933		537,042		0		11,756,750

		Net Margins	$	8,991,093	$	2,119,877	$	2,409,308	$	441,859	$	2,642,119	$	968,080	$	20,260,127	$	1,324,985	$	168,635,377

FINANCIAL AND STATISTICAL INFORMATION FOR
38 MEMBERS OF OGLETHORPE POWER CORPORATION

				Altamaha		Amicalola		Canoochee		Carroll		Central Georgia		Coastal		Cobb(1)		Colquitt		Coweta- Fayette		Diverse

2008
ASSETS
	Total Utility Plant(2)			$	82,495,551	$	167,046,816	$	107,108,995	$	206,128,177	$	176,108,011	$	67,909,550	$	650,704,629	$	186,117,283	$	267,256,930	$	124,153,498
	Depreciation			$	22,773,534	$	41,897,122	$	32,599,847	$	38,776,346	$	30,501,372	$	12,075,581	$	134,885,908	$	45,458,964	$	64,198,988	$	43,390,277

		Net Plant			59,722,017		125,149,694		74,509,148		167,351,831		145,606,639		55,833,969		515,818,721		140,658,319		203,057,942		80,763,221
	Other Assets				32,186,462		20,071,476		19,000,130		39,724,406		36,401,524		14,116,142		331,876,450		50,719,753		60,990,505		21,451,335

			Total Assets	$	91,908,479	$	145,221,170	$	93,509,278	$	207,076,237	$	182,008,163	$	69,950,111	$	847,695,171	$	191,378,072	$	264,048,447	$	102,214,556

EQUITY & LIABILITIES
	Equity			$	58,967,436	$	58,983,153	$	34,912,014	$	66,739,541	$	61,174,119	$	21,528,070	$	256,287,951	$	82,520,062	$	75,378,036	$	45,205,340
	Long-term Debt				23,733,197		55,332,341		39,056,075		103,380,963		98,578,433		41,640,303		385,174,620		78,587,966		136,488,542		44,995,652
	Other Liabilities				9,207,846		30,905,676		19,541,189		36,955,733		22,255,611		6,781,738		206,232,600		30,270,044		52,181,869		12,013,564

		Total Equity and Liabilities		$	91,908,479	$	145,221,170	$	93,509,278	$	207,076,237	$	182,008,163	$	69,950,111	$	847,695,171	$	191,378,072	$	264,048,447	$	102,214,556

2007
ASSETS
	Total Utility Plant(2)			$	79,713,398	$	160,949,116	$	101,850,091	$	192,880,900	$	168,967,910	$	63,605,531	$	617,716,224	$	174,771,455	$	251,599,738	$	110,660,407
	Depreciation				21,172,829		39,889,725		33,152,951		37,086,124		28,360,162		11,625,531		118,476,223		41,111,016		58,415,901		39,690,389

		Net Plant			58,540,569		121,059,391		68,697,140		155,794,776		140,607,748		51,980,000		499,240,001		133,660,439		193,183,837		70,970,018
	Other Assets				31,515,701		21,440,776		19,087,496		43,652,662		36,162,398		12,526,765		315,272,091		55,809,764		57,079,263		16,520,755

			Total Assets	$	90,056,270	$	142,500,167	$	87,784,636	$	199,447,438	$	176,770,146	$	64,506,765	$	814,512,092	$	189,470,203	$	250,263,100	$	87,490,773

EQUITY & LIABILITIES
	Equity			$	58,668,872	$	59,140,663	$	32,678,895	$	64,855,484	$	60,557,734	$	19,936,206	$	256,449,237	$	82,730,590	$	67,926,515	$	44,116,010
	Long-term Debt				22,769,872		51,169,460		43,532,777		99,394,624		101,351,108		29,307,627		363,883,062		95,345,824		141,180,691		32,048,206
	Other Liabilities				8,617,526		32,190,044		11,572,964		35,197,330		14,861,304		15,262,932		194,179,793		11,393,789		41,155,894		11,326,557

		Total Equity and Liabilities		$	90,056,270	$	142,500,167	$	87,784,636	$	199,447,438	$	176,770,146	$	64,506,765	$	814,512,092	$	189,470,203	$	250,263,100	$	87,490,773

2006
ASSETS
	Total Utility Plant(2)			$	75,680,592	$	150,420,968	$	94,645,201	$	177,648,571	$	152,093,523	$	57,886,144	$	568,881,901	$	162,683,913	$	236,595,078	$	102,513,802
	Depreciation				19,263,622		37,625,396		33,512,101		32,344,092		26,660,315		10,935,638		105,674,895		37,199,077		53,442,571		37,383,394

		Net Plant			56,416,970		112,795,572		61,133,100		145,304,479		125,433,208		46,950,506		463,207,006		125,484,836		183,152,507		65,130,408
	Other Assets				34,085,257		20,443,027		20,751,492		54,251,310		32,887,448		10,777,344		305,574,374		55,358,633		56,242,591		15,168,805

			Total Assets	$	90,502,227	$	133,238,599	$	81,884,592	$	199,555,789	$	158,320,656	$	57,727,850	$	768,781,380	$	180,843,469	$	239,395,098	$	80,299,213

EQUITY & LIABILITIES
	Equity			$	58,031,152	$	54,431,741	$	31,504,239	$	69,913,483	$	57,488,946	$	19,173,088	$	252,429,739	$	80,755,740	$	62,116,719	$	45,012,359
	Long-term Debt				21,730,214		53,599,995		40,043,493		102,814,311		86,138,503		30,241,920		332,266,714		68,681,761		145,599,660		27,139,860
	Other Liabilities				10,740,861		25,206,863		10,336,860		26,827,995		14,693,207		8,312,842		184,084,927		31,405,968		31,678,719		8,146,994

		Total Equity and Liabilities		$	90,502,227	$	133,238,599	$	81,884,592	$	199,555,789	$	158,320,656	$	57,727,850	$	768,781,380	$	180,843,469	$	239,395,098	$	80,299,213

				Middle Georgia		Mitchell		Ocmulgee		Oconee		Okefenoke		Planters		Rayle		Satilla		Sawnee		Slash Pine
2008
ASSETS
	Total Utility Plant(2)			$	33,658,534	$	116,535,708	$	45,513,358	$	58,838,910	$	145,389,564	$	54,419,037	$	79,167,821	$	154,288,304	$	437,409,703	$	27,327,689
	Depreciation				5,589,012		20,465,781		10,810,763		11,271,809		34,847,741		16,093,821		23,611,687		27,911,642		75,580,648		6,970,853

		Net Plant			28,069,522		96,069,927		34,702,595		47,567,101		110,541,823		38,325,216		55,556,134		126,376,662		361,829,055		20,356,836
	Other Assets				7,474,938		19,548,409		8,908,057		13,978,032		26,761,701		15,626,779		11,930,590		40,317,030		85,853,895		8,133,585

			Total Assets	$	35,544,460	$	115,618,336	$	43,610,652	$	61,545,133	$	137,303,524	$	53,951,995	$	67,486,724	$	166,693,692	$	447,682,950	$	28,490,421

EQUITY & LIABILITIES
	Equity			$	12,683,344	$	61,566,287	$	17,239,189	$	19,368,961	$	42,340,867	$	24,758,076	$	16,959,117	$	61,809,620	$	152,398,666	$	9,620,890
	Long-term Debt				15,248,363		40,334,697		20,175,663		32,054,321		82,459,154		25,285,956		41,661,740		62,880,633		240,752,641		12,274,145
	Other Liabilities				7,612,753		13,717,352		6,195,800		10,121,851		12,503,503		3,907,963		8,865,867		42,003,439		54,531,643		6,595,386

		Total Equity and Liabilities		$	35,544,460	$	115,618,336	$	43,610,652	$	61,545,133	$	137,303,524	$	53,951,995	$	67,486,724	$	166,693,692	$	447,682,950	$	28,490,421

2007
ASSETS
	Total Utility Plant(2)			$	30,653,167	$	109,535,852	$	43,648,393	$	55,450,664	$	140,788,522	$	51,300,300	$	74,527,512	$	146,669,772	$	417,376,651	$	25,980,211
	Depreciation				5,346,915		18,749,803		10,073,548		10,037,558		32,780,439		14,913,168		21,912,852		24,873,565		70,251,603		6,452,064

		Net Plant			25,306,252		90,786,049		33,574,845		45,413,106		108,008,083		36,387,132		52,614,660		121,796,207		347,125,048		19,528,147
	Other Assets				6,911,379		20,723,819		8,379,085		12,786,941		23,187,925		14,956,667		12,915,427		34,337,538		148,336,152		8,070,197

			Total Assets	$	32,217,631	$	111,509,868	$	41,953,930	$	58,200,047	$	131,196,008	$	51,343,799	$	65,530,087	$	156,133,745	$	495,461,200	$	27,598,344

EQUITY & LIABILITIES
	Equity			$	12,074,173	$	59,675,211	$	16,103,716	$	18,748,778	$	42,025,900	$	23,807,487	$	17,303,775	$	54,446,363	$	139,479,816	$	9,116,969
	Long-term Debt				15,786,894		33,549,024		19,943,709		31,490,159		78,193,125		23,476,540		40,904,941		64,747,741		311,458,530		12,670,631
	Other Liabilities				4,356,564		18,285,633		5,906,505		7,961,110		10,976,983		4,059,772		7,321,371		36,939,641		44,522,854		5,810,744

		Total Equity and Liabilities		$	32,217,631	$	111,509,868	$	41,953,930	$	58,200,047	$	131,196,008	$	51,343,799	$	65,530,087	$	156,133,745	$	495,461,200	$	27,598,344

2006
ASSETS
	Total Utility Plant(2)			$	28,571,363	$	103,595,814	$	41,939,842	$	51,986,720	$	128,101,912	$	49,408,481	$	70,229,868	$	139,142,208	$	384,099,810	$	24,624,605
	Depreciation				5,229,858		17,238,679		9,460,397		9,354,566		30,385,604		14,303,110		20,404,776		23,076,675		65,591,862		6,111,533

		Net Plant			23,341,505		86,357,135		32,479,445		42,632,154		97,716,308		35,105,371		49,825,092		116,065,533		318,507,948		18,513,072
	Other Assets				5,191,813		19,205,412		9,139,319		11,999,837		21,934,828		14,585,715		10,596,025		37,269,217		59,943,770		6,858,952

			Total Assets	$	28,533,318	$	105,562,547	$	41,618,764	$	54,631,991	$	119,651,136	$	49,691,086	$	60,421,117	$	153,334,750	$	378,451,718	$	25,372,024

EQUITY & LIABILITIES
	Equity			$	11,700,362	$	60,253,735	$	16,553,907	$	17,833,057	$	39,126,889	$	23,066,398	$	17,436,367	$	54,922,073	$	127,473,251	$	8,288,600
	Long-term Debt				14,402,577		28,706,819		20,685,010		27,118,627		61,954,482		22,093,576		35,065,618		54,607,041		195,021,558		12,499,991
	Other Liabilities				2,430,379		16,601,993		4,379,847		9,680,307		18,569,765		4,531,112		7,919,132		43,805,636		55,956,909		4,583,433

		Total Equity and Liabilities		$	28,533,318	$	105,562,547	$	41,618,764	$	54,631,991	$	119,651,136	$	49,691,086	$	60,421,117	$	153,334,750	$	378,451,718	$	25,372,024

				Excelsior		Grady		GreyStone		Habersham		Hart		Irwin		Jackson		Jefferson		Little Ocmulgee

2008
ASSETS
	Total Utility Plant(2)			$	64,063,411	$	74,974,010	$	372,089,733	$	125,051,609	$	141,491,403	$	64,728,759	$	733,883,156	$	125,308,897	$	46,959,322
	Depreciation			$	14,199,023	$	14,843,265	$	61,436,860	$	36,160,650	$	34,378,637	$	17,126,378	$	171,230,146	$	26,655,182	$	11,023,442

		Net Plant			49,864,388		60,130,745		310,652,873		88,890,959		107,112,766		47,602,381		562,653,010		98,653,715		35,935,880
	Other Assets				17,407,023		16,253,832		75,564,651		18,068,766		26,312,088		9,353,569		191,016,588		35,256,471		7,514,047

			Total Assets	$	67,271,411	$	76,384,577	$	386,217,524	$	106,959,725	$	133,424,854	$	56,955,950	$	753,669,598	$	133,910,186	$	43,449,927

EQUITY & LIABILITIES
	Equity			$	37,271,800	$	36,701,668	$	143,581,680	$	35,222,703	$	55,220,972	$	18,209,425	$	260,205,011	$	52,957,044	$	13,484,517
	Long-term Debt				23,344,081		24,546,047		198,955,162		56,806,225		59,862,111		35,284,374		371,345,021		61,540,892		25,184,369
	Other Liabilities				6,655,530		15,136,862		43,680,682		14,930,797		18,341,771		3,462,151		122,119,566		19,412,250		4,781,041

		Total Equity and Liabilities		$	67,271,411	$	76,384,577	$	386,217,524	$	106,959,725	$	133,424,854	$	56,955,950	$	753,669,598	$	133,910,186	$	43,449,927

2007
ASSETS
	Total Utility Plant(2)			$	61,423,133	$	70,090,055	$	351,215,886	$	119,456,685	$	133,707,622	$	61,677,486	$	694,908,275	$	118,232,343	$	45,150,518
	Depreciation				13,547,723		13,494,511		58,860,638		32,531,960		32,505,391		16,263,931		155,502,853		24,144,090		10,671,327

		Net Plant			47,875,410		56,595,544		292,355,248		86,924,725		101,202,231		45,413,555		539,405,422		94,088,253		34,479,191
	Other Assets				19,347,536		14,741,142		83,069,787		17,797,730		26,297,870		9,474,914		193,967,686		31,245,995		6,319,389

			Total Assets	$	67,222,946	$	71,336,686	$	375,425,035	$	104,722,455	$	127,500,101	$	54,888,469	$	733,373,108	$	125,334,248	$	40,798,580

EQUITY & LIABILITIES
	Equity			$	35,792,073	$	34,572,171	$	139,082,062	$	34,427,590	$	51,142,114	$	17,498,207	$	247,974,272	$	50,154,536	$	12,916,298
	Long-term Debt				23,788,746		25,162,241		189,504,327		58,070,782		59,928,598		29,086,570		358,930,458		56,873,250		22,943,277
	Other Liabilities				7,642,127		11,602,274		46,838,646		12,224,083		16,429,389		8,303,692		126,468,378		18,306,462		4,939,005

		Total Equity and Liabilities		$	67,222,946	$	71,336,686	$	375,425,035	$	104,722,455	$	127,500,101	$	54,888,469	$	733,373,108	$	125,334,248	$	40,798,580

2006
ASSETS
	Total Utility Plant(2)			$	59,042,364	$	66,289,506	$	315,548,377	$	115,174,455	$	124,723,672	$	56,215,768	$	648,333,788	$	110,314,624	$	42,656,195
	Depreciation				12,602,886		12,621,455		53,818,667		29,650,777		30,844,387		15,617,614		140,094,597		21,755,628		10,151,837

		Net Plant			46,439,478		53,668,051		261,729,710		85,523,678		93,879,285		40,598,154		508,239,191		88,558,996		32,504,358
	Other Assets				21,138,639		14,751,160		75,735,186		16,191,762		20,622,726		9,353,436		206,738,335		32,333,219		7,265,908

			Total Assets	$	67,578,117	$	68,419,211	$	337,464,896	$	101,715,440	$	114,502,011	$	49,951,590	$	714,977,526	$	120,892,215	$	39,770,266

EQUITY & LIABILITIES
	Equity			$	34,054,440	$	33,481,319	$	127,999,885	$	33,414,937	$	48,027,176	$	16,963,348	$	232,028,386	$	47,618,311	$	12,849,893
	Long-term Debt				24,622,407		23,179,603		162,199,878		55,162,088		51,292,611		28,656,567		357,277,815		56,773,060		21,681,047
	Other Liabilities				8,901,270		11,758,289		47,265,133		13,138,415		15,182,224		4,331,675		125,671,325		16,500,844		5,239,326

		Total Equity and Liabilities		$	67,578,117	$	68,419,211	$	337,464,896	$	101,715,440	$	114,502,011	$	49,951,590	$	714,977,526	$	120,892,215	$	39,770,266

				Snapping Shoals		Southern Rivers		Sumter		Three Notch		Tri-County		Upson		Walton		Washington		MEMBER TOTAL
2008
ASSETS
	Total Utility Plant(2)			$	238,977,522	$	59,527,615	$	89,381,778	$	48,712,574	$	89,405,173	$	23,562,155	$	337,377,996	$	67,909,418	$	5,890,982,599
	Depreciation			$	63,687,898	$	16,024,887	$	17,968,485	$	13,906,096	$	13,406,421	$	6,561,100	$	95,692,179	$	19,395,353		1,333,407,698

		Net Plant			175,289,624		43,502,728		71,413,293		34,806,478		75,998,752		17,001,055		241,685,817		48,514,065		4,557,574,901
	Other Assets				55,007,665		9,914,640		20,298,930		15,475,705		13,659,875		11,592,930		175,390,745		22,453,576		1,585,612,300

			Total Assets	$	230,297,289	$	53,417,368	$	91,712,223	$	50,282,183	$	89,658,627	$	28,593,985	$	417,076,562	$	70,967,641	$	6,143,187,201

EQUITY & LIABILITIES
	Equity			$	88,210,742	$	20,401,172	$	39,593,272	$	19,020,617	$	27,329,787	$	13,723,135	$	159,099,493	$	33,011,879	$	2,233,685,656
	Long-term Debt				91,080,692		24,681,610		45,625,745		25,806,634		54,577,419		11,381,702		186,987,899		32,654,884		2,909,760,272
	Other Liabilities				51,005,855		8,334,586		6,493,206		5,454,932		7,751,421		3,489,148		70,989,170		5,300,878		999,741,273

		Total Equity and Liabilities		$	230,297,289	$	53,417,368	$	91,712,223	$	50,282,183	$	89,658,627	$	28,593,985	$	417,076,562	$	70,967,641	$	6,143,187,201

2007
ASSETS
	Total Utility Plant(2)			$	229,068,284	$	55,412,509	$	83,112,588	$	46,456,805	$	84,957,989	$	22,789,466	$	318,078,172	$	64,212,260	$	5,578,595,890
	Depreciation				57,422,901		14,919,630		18,073,378		12,943,582		13,318,514		6,036,861		88,846,389		18,449,517		1,231,905,562

		Net Plant			171,645,383		40,492,879		65,039,210		33,513,223		71,639,475		16,752,605		229,231,783		45,762,743		4,346,690,328
	Other Assets				40,316,565		13,372,446		18,447,178		14,654,333		12,087,374		11,728,026		170,343,532		21,223,251		1,604,107,555

			Total Assets	$	211,961,948	$	53,865,325	$	83,486,388	$	48,167,556	$	83,726,849	$	28,480,631	$	399,575,315	$	66,985,994	$	5,950,797,883

EQUITY & LIABILITIES
	Equity			$	82,633,413	$	20,916,154	$	36,658,250	$	18,821,930	$	26,047,357	$	13,010,028	$	154,111,608	$	33,054,470	$	2,148,654,927
	Long-term Debt				84,594,274		25,924,000		40,069,534		25,746,593		47,208,849		11,665,827		184,312,663		28,852,148		2,884,866,682
	Other Liabilities				44,734,261		7,025,171		6,758,604		3,599,033		10,470,643		3,804,776		61,151,044		5,079,376		917,276,274

		Total Equity and Liabilities		$	211,961,948	$	53,865,325	$	83,486,388	$	48,167,556	$	83,726,849	$	28,480,631	$	399,575,315	$	66,985,994	$	5,950,797,883

2006
ASSETS
	Total Utility Plant(2)			$	208,851,716	$	51,047,947	$	77,040,045	$	44,230,092	$	77,629,642	$	21,805,999	$	297,497,813	$	61,507,530	$	5,178,659,849
	Depreciation				55,274,615		14,520,801		17,101,436		12,124,817		12,792,744		5,630,924		83,090,075		17,645,093		1,140,536,514

		Net Plant			153,577,101		36,527,146		59,938,609		32,105,275		64,836,898		16,175,075		214,407,738		43,862,437		4,038,123,335
	Other Assets				38,274,211		13,271,733		17,130,922		15,784,554		12,805,123		11,228,554		168,639,454		22,787,785		1,506,317,876

			Total Assets	$	191,851,312	$	49,798,879	$	77,069,531	$	47,889,829	$	77,642,021	$	27,403,629	$	383,047,192	$	66,650,222	$	5,544,441,211

EQUITY & LIABILITIES
	Equity			$	78,149,640	$	20,438,722	$	34,292,448	$	18,616,656	$	25,027,435	$	13,020,101	$	147,085,457	$	32,327,316	$	2,062,907,315
	Long-term Debt				75,510,883		22,806,198		36,256,628		25,078,600		45,716,642		10,464,287		176,120,957		29,468,711		2,582,679,712
	Other Liabilities				38,190,789		6,553,959		6,520,455		4,194,573		6,897,944		3,919,241		59,840,778		4,854,195		898,854,184

		Total Equity and Liabilities		$	191,851,312	$	49,798,879	$	77,069,531	$	47,889,829	$	77,642,021	$	27,403,629	$	383,047,192	$	66,650,222	$	5,544,441,211

No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to exchange only the exchange bonds offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

Until September 10, 2009, the date that is 90 days from the date of this prospectus, all dealers that effect transactions in these securities, whether or not participating in the exchange offer, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters with respect to their unsold allotments or subscriptions.


Oglethorpe Power Corporation		We are a Georgia electric membership corporation incorporated in 1974 and headquartered in metropolitan Atlanta. We are owned by 38 retail electric distribution cooperative members. Our principal business is providing wholesale electric power to our members. As with cooperatives generally, we operate on a not-for-profit basis. We are the largest electric cooperative in the United States in terms of assets, kilowatt-hour sales to members, and, through our members, consumers served.
		Our members are local consumer-owned distribution cooperatives providing retail electric service on a not-for-profit basis. In general, our members' customer base consists of residential, commercial and industrial consumers within specific geographic areas. Our members serve approximately 1.7 million electric consumers (meters) representing approximately 4.1 million people.
		Our principal executive offices are located at 2100 East Exchange Place, Tucker, Georgia 30084-5336. Our telephone number is (770) 270-7600. We maintain a website at www.opc.com. Information contained on this website is not incorporated by reference into this prospectus and information contained on this website should not be considered to be part of this prospectus.
Cooperative Principles		We are organized and operate as a cooperative. A cooperative is a business organization owned by its members, which also are its customers. Cooperatives are created to provide goods or services to their members on a not-for-profit basis.


Securities Offered		$350,000,000 aggregate principal amount of 6.10% First Mortgage Bonds, Series 2009 A due 2019.
Maturity Date		The exchange bonds will mature on March 15, 2019.
Interest and Payment Dates		Interest on the exchange bonds will accrue from the last date on which interest was paid on the original bonds surrendered in this exchange offer, or if no interest has been paid, from the date of original issuance of the original bonds at the rate per year set forth on the cover page of this prospectus. We will pay interest on the exchange bonds semi-annually on March 15 and September 15, beginning on September 15, 2009.
Make-Whole Redemption		We may redeem the exchange bonds, in whole or in part, prior to their stated maturity, at our option at the "make-whole redemption" price described in this prospectus under "THE EXCHANGE BONDS—Make-Whole Redemption."
Indenture		We will issue the exchange bonds under the Indenture dated March 1, 1997, made by us to U.S. Bank National Association, as amended and supplemented. The indenture constitutes a first priority lien on substantially all of our owned tangible and certain of our intangible assets. See "SUMMARY OF THE INDENTURE."
No Prior Market		The exchange bonds have no established trading market. We do not intend to list the exchange bonds on any securities exchange. Accordingly, we cannot assure you whether a market for the exchange bonds will develop or as to the liquidity of any market that may develop. If no active trading market develops, you may not be able to resell the exchange bonds at their fair market value or at all.


Limitation on Distributions to Members	The indenture prohibits us from making any distribution, including any dividends, or payments of, or retirements of, patronage capital to our members if at the time of or as a result of the distribution:
	•	we are in default under the indenture;
	•	our equity as of the end of the immediately preceding fiscal quarter is less than 20% of our total long-term debt and equities (as stated in the table on "SELECTED FINANCIAL DATA"); or
	•	the aggregate amount expended for the distributions on or after the date on which our equity first reaches 20% of our total long-term debt and equities exceeds 35% of our aggregate net margins earned after that date.
	The restrictions set forth in the second and third bullet points above, however, would not apply if, after giving effect to the distribution, payment or retirement, our equity as of the end of the immediately preceding fiscal quarter is not less than 30% of our total long-term debt and equities. See "SUMMARY OF THE INDENTURE—Covenants."

				As of March 31,			As of December 31,

				2009			2008			2007			2006			2005			2004
				(in thousands)			(in thousands)
Balance Sheet Data:
	Assets:
		Total electric plant		$	3,696,614		$	3,639,395		$	3,481,194		$	3,461,301		$	3,547,981		$	3,658,108
		Total assets		$	5,451,194		$	5,044,452		$	4,937,320		$	4,901,745		$	4,826,916		$	4,813,042
Capitalization:
		Patronage capital and membership fees		$	551,476		$	535,829		$	516,570		$	497,509		$	479,308		$	461,655
		Accumulated other comprehensive deficit		$	(1,173	)	$	(1,348	)	$	(32,691	)	$	(28,988	)	$	(35,498	)	$	(46,760	)

			Subtotal	$	550,303		$	534,481		$	483,879		$	468,521		$	443,810		$	414,895
		Long-term debt and obligations under capital leases		$	3,890,857		$	3,514,923		$	3,552,367		$	3,481,294		$	3,353,339		$	3,505,241
		Obligation under Rocky Mountain transactions		$	110,044		$	108,219		$	101,272		$	94,772		$	88,689		$	83,012
		Long-term debt and capital leases due within one year		$	112,929		$	110,647		$	143,400		$	234,621		$	217,743		$	190,835
			Total long-term debt and equities	$	4,664,133		$	4,268,270		$	4,280,918		$	4,279,208		$	4,103,581		$	4,193,983

			Three Months Ended March 31,						Years Ended December 31,

			2009			2008			2008			2007			2006			2005			2004
			(in thousands, except other selected data)						(in thousands, except other selected data)
Statement of Revenues and Expenses:
	Operating revenues:
		Sales to members	$	281,705		$	291,310		$	1,237,649		$	1,149,657		$	1,127,423		$	1,136,463		$	1,279,465
		Sales to non-members	$	308		$	333		$	1,111		$	1,585		$	1,456		$	33,060		$	33,307
	Operating expenses		$	219,933		$	239,055		$	1,041,681		$	964,014		$	942,582		$	958,100		$	1,108,919
	Other income (expense)		$	10,460		$	11,526		$	43,381		$	54,854		$	51,414		$	26,776		$	36,437
	Net interest charges		$	56,893		$	57,447		$	221,201		$	223,021		$	219,510		$	220,546		$	223,053
Net margin			$	15,647		$	6,667		$	19,259		$	19,061		$	18,201		$	17,653		$	17,237

Other Selected Data:
	Kilowatt hours sold to members (in thousands)			4,831,378			5,348,914			23,308,911			22,815,174			23,019,482			23,721,939			31,213,210
	Revenues per Kilowatt hour			5.83	¢		5.45	¢		5.30	¢		5.04	¢		4.90	¢		4.79	¢		4.10	¢
	Margins for Interest ratio(1)			N/A			N/A			1.10			1.10			1.10			1.10			1.10
	Equity Ratio(2)			11.8	%					12.6	%		12.1	%		11.6	%		11.7	%		11.0	%


Exchange Agent		U.S. Bank National Association is the exchange agent for the exchange offer. Any requests for assistance, requests for additional copies of this prospectus or of the letter of transmittal and requests for the notice of guaranteed delivery should be directed towards the exchange agent. The address and telephone number of the exchange agent are provided in the section captioned "THE EXCHANGE OFFER—Exchange Agent."


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

			Member Energy Requirements (Megawatt-hours)

	Member Demand (Megawatts)		Member Energy Requirements (Megawatt-hours)
	Member Demand (Megawatts)				Supplied by Oglethorpe(3)
	Total(1)		Total(2)		Supplied by Oglethorpe(3)
2006		8,094		34,973,868		23,019,482
2007		8,907		35,944,150		22,815,174
2008		8,576		35,805,709		23,308,911

Facilities		Type of Fuel

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	2047
	Unit No. 2	Nuclear	30	348.0		1989	2049
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)
Heard (near Franklin, Ga.)(3)		Gas	100	500.0		2001	N/A	(1)

	Total			5,243.9

		Equivalent Availability(1)									Capacity Factor(2)

Unit		2008			2007			2006			2008			2007			2006
Plant Hatch
	Unit No. 1		83	%		97	%		85	%		84	%		98	%		86	%
	Unit No. 2		96			87			98			96			87			99
Plant Vogtle
	Unit No. 1		89			100			85			91			101			86
	Unit No. 2		86			83			91			88			84			92
Plant Wansley
	Unit No. 1		98			83			98			85			77			88
	Unit No. 2		88			98			85			72			91			77
Plant Scherer
	Unit No. 1		97			86			90			90			80			80
	Unit No. 2		97			90			97			92			85			87
Rocky Mountain(3)
	Unit No. 1		97			86			91			26			22			24
	Unit No. 2		93			97			88			21			25			17
	Unit No. 3		76			37			78			11			6			16
Doyle(3)(4)			95			92			100			1			2			2
Talbot(3)			94			90			96			1			3			2
Chattahoochee			88			91			95			34			38			22

	Nuclear								Coal-Fired								Pumped Storage

	Plant Hatch				Plant Vogtle				Plant Wansley				Scherer Units No. 1 & No. 2				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
Georgia Power		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

	Authorized Amount		Available 3/31/2009		Available 6/1/2009		Expiration Date

Commercial Paper Line of Credit	$	450	$	450	$	242	July 2012
CoBank Line of Credit		50		50		50	December 2009
Cooperative Finance Corp. Line of Credit		50		50		50	October 2011

Total	$	550	$	550	$	342

Participant Banks in $450 Million Credit Facility	Commitment

	(dollars in millions)
Bank of America, N.A.—Administrative Agent	$	75
SunTrust Bank	$	75
The Bank of Tokyo—Mitsubishi UFJ, Ltd.	$	60
CoBank, ACB	$	60
JPMorgan Chase Bank, National Association	$	60
National Rural Utilities Cooperative Finance Corporation	$	60
Wachovia Bank, N.A. (a Wells Fargo company)	$	60

	2009		2010		2011		Total

Future Generation(2)	$	375	$	474	$	537	$	1,386
Existing Generation(3)		93		63		72		228
Environmental Compliance(4)		137		117		190		444
Nuclear Fuel		89		101		100		290
General Plant		4		2		1		7

Total	$	698	$	757	$	900	$	2,355

		2009		2010-2011		2012-2013		Beyond 2013		Total

Long-Term Debt:
	Principal	$	84	$	180	$	184	$	3,263	$	3,711
	Interest(1)		202		398		378		2,127		3,105
Capital Leases(2)			44		89		81		161		375
Operating Leases			5		11		12		25		53
Unconditional Power Purchases			29		60		63		203		355
Rocky Mountain Lease Arrangements(3)			—		—		—		372		372
Chattahoochee O&M Agmts.			21		43		43		117		224
Asset Retirement Obligations(4)			—		—		—		2,456		2,456

Total		$	385	$	781	$	761	$	8,724	$	10,651

Oglethorpe Ratings

Senior secured debt	A		A3	A
Short-term/commercial paper	A-1		P-2	F1
Issuer rating	n/a	⁽¹⁾	Baa1	n/a	⁽¹⁾

Goal

Operations	33	%
Financial	30	%
Quality	20	%
Environmental Compliance	10	%
Safety	5	%
Corporate Compliance	2	%

Executive Officer	Performance Pay*

Thomas A. Smith	$	94,270
Michael W. Price	$	54,848
Elizabeth B. Higgins	$	54,848
William F. Ussery	$	42,850
W. Clayton Robbins	$	35,994
Jami G. Reusch	$	27,253

Name and Principal Position			Salary		Non-Equity Incentive Plan Compensation		All Other Compensation(1)		Total

Thomas A. Smith		2008	$	537,500	$	94,270	$	74,439	$	706,209
	President and Chief Executive Officer	2007		469,313		77,425		68,332		615,070
		2006		438,043		72,126		51,582		561,751
Michael W. Price		2008		305,208		54,848		48,496		408,552
	Executive Vice President, Chief	2007		275,853		45,640		57,261		378,754
	Operating Officer	2006		253,481		44,059		35,925		333,465
Elizabeth B. Higgins		2008		304,375		54,848		47,960		407,183
	Executive Vice President, Chief	2007		270,314		44,825		44,722		359,861
	Financial Officer	2006		245,304		42,637		35,112		323,053
William F. Ussery		2008		227,125		42,850		39,721		309,696
	Executive Vice President, Member and	2007		190,283		31,622		36,087		257,992
	External Relations	2006		171,417		29,653		27,697		228,767
W. Clayton Robbins		2008		187,417		35,994		49,123		272,534
	Senior Vice President, Governmental	2007		170,667		28,036		64,126		262,829
	Affairs	2006		154,487		26,273		73,550		254,310
Jami G. Reusch		2008		161,620		27,253		32,362		221,235
	Vice President, Human Resources	2007		154,766		25,428		32,081		212,275
		2006		147,643		23,805		27,341		198,789

Name		Position

Executive Officers:
Thomas A. Smith	54	President and Chief Executive Officer
Michael W. Price	48	Executive Vice President and Chief Operating Officer
Elizabeth B. Higgins	40	Executive Vice President and Chief Financial Officer
William F. Ussery	44	Executive Vice President, Member and External Relations
W. Clayton Robbins	62	Senior Vice President, Governmental Affairs
Jami G. Reusch	46	Vice President, Human Resources
Directors:
Benny W. Denham	78	Chairman and At-Large Director
Marshall S. Millwood	59	At-Large Director
Bobby C. Smith, Jr.	55	At-Large Director
Larry N. Chadwick	68	Member Group Director (Group 1)
Gary W. Wyatt	56	Member Group Director (Group 1)
H.B. Wiley, Jr.	64	Member Group Director (Group 2)
Rick L. Gaston	61	Member Group Director (Group 2)
M. Anthony Ham	57	Member Group Director (Group 3)
C. Hill Bentley	61	Member Group Director (Group 3)
J. Sam L. Rabun	77	Vice-Chairman and Member Group Director (Group 4)
Jeffrey W. Murphy	45	Member Group Director (Group 4)
G. Randall Pugh	65	Member Group Director (Group 5)
Wm. Ronald Duffey	67	Outside Director

Name	Total Fees Earned or Paid in Cash

Member Directors
Benny W. Denham, Chairman	$	14,940
J. Sam L. Rabun, Vice-Chairman	$	17,500
Marshall S. Millwood	$	14,500
Larry N. Chadwick	$	14,100
M. Anthony Ham	$	13,400
H.B. Wiley, Jr.	$	14,100
Gary A. Miller(1)	$	9,500
Jeffrey W. Murphy	$	12,300
C. Hill Bentley	$	12,300
Gary W. Wyatt	$	12,000
R.L. Gaston	$	5,700
Bobby C. Smith, Jr.	$	9,900
G. Randall Pugh	$	5,600	(2)
Outside Directors
Wm. Ronald Duffey	$	33,700

Goal

Operations	25.56	%
Financial	30.00	%
Quality	15.66	%
Environmental Compliance	8.50	%
Safety	5.00	%
Corporate Compliance	1.00	%
Total	85.72	%

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards

	Grant Date
Name	Grant Date	Threshold(1)		Target(2)
Thomas A. Smith President and Chief Executive Officer	N/A	$	22,275	$	110,000
Michael W. Price Executive Vice President and Chief Operating Officer	N/A		12,960		64,000
Elizabeth B. Higgins Executive Vice President and Chief Financial Officer	N/A		12,960		64,000
William F. Ussery Executive Vice President, Member and External Relations	N/A		10,125		50,000
W. Clayton Robbins Senior Vice President, Governmental Affairs	N/A		8,505		42,000
Jami G. Reusch Vice President, Human Resources	N/A		6,440		31,800

Name	Registrant Contributions in Last FY(1)		Aggregate Earnings in Last FY(2)			Aggregate Balance at Last FYE

Thomas A. Smith President and Chief Executive Officer	$	30,794	$	(24,347	)	$	52,022
Michael W. Price Executive Vice President and Chief Operating Officer		9,668		(2,976	)		21,536
Elizabeth B. Higgins Executive Vice President and Chief Financial Officer		9,536		(5,345	)		16,618
William F. Ussery Executive Vice President, Member and External Relations		2,300		80			2,379
W. Clayton Robbins Senior Vice President, Governmental Affairs		—		(630	)		1,071
Jami G. Reusch Vice President, Human Resources		—		—			—


By Registered or Certified Mail, Overnight Courier or Hand Delivery: U.S. Bank National Association West Side Flats Operations Center Attention: Specialized Finance 60 Livingston Avenue Mail Station—EP-MN-WS2N St. Paul, Minnesota 55107-2292		By Facsimile: (Eligible Institutions Only) (651) 495-8158 Attention: Specialized Finance Confirm by Telephone or for Information: (800) 934-6802

		Patronage Capital and Membership Fees		Accumulated Other Comprehensive (Deficit)			Total

		(dollars in thousands)
Balance at December 31, 2007		$	516,570	$	(32,691	)	$	483,879

Components of comprehensive margin:
	Net margin		6,667		—			6,667
	Realized deferred loss on interest rate swap arrangements		—		32,806			32,806
	Unrealized loss on available-for-sale securities		—		(2,553	)		(2,553	)

Total comprehensive margin								36,920

Balance at March 31, 2008		$	523,237	$	(2,438	)	$	520,799

Balance at December 31, 2008		$	535,829	$	(1,348	)	$	534,481

Components of comprehensive margin:
	Net margin		15,647		—			15,647
	Unrealized gain on available-for-sale securities		—		175			175

Total comprehensive margin								15,822

Balance at March 31, 2009		$	551,476	$	(1,173	)	$	550,303

	Fair Value Measurements at Reporting Date Using

	March 31, 2009			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Decommissioning funds	$	190,388		$	178,630	$	10,318		$	1,440
Bond, reserve and construction funds		3,513			3,513		—			—
Long-term investments		80,059			50,440		—			29,619	(1)
Natural gas swaps		(35,432	)		—		(35,432	)		—
Deposit on Rocky Mountain transactions		110,044			—		—			110,044
Investments in associated companies		43,845			—		—			43,845

	Fair Value Measurements at Reporting Date Using

	December 31, 2008			Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)			Significant Unobservable Inputs (Level 3)
Decommissioning funds	$	201,094		$	184,854	$	10,155		$	6,085
Bond, reserve and construction funds		4,560			4,560		—			—
Long-term investments		81,550			51,907		—			29,643	(1)
Natural gas swaps		(18,836	)		—		(18,836	)		—
Deposit on Rocky Mountain transactions		108,219			—		—			108,219
Investments in associated companies		43,441			—		—			43,441

		Three Months Ended March 31, 2009

Assets:		Decommissioning funds			Long-term investments			Deposit on Rocky Mountain transactions		Investments in associated companies
Balance at December 31, 2008		$	6,085		$	29,643		$	108,219	$	43,441
Total gains or losses (realized/unrealized):
	Impairment included in other comprehensive deficit		—			(24	)		—		—
Transfers to Level 3			(4,645	)		—			1,825		404

Balance at March 31, 2009		$	1,440		$	29,619		$	110,044	$	43,845

Liabilities:		Interest Rate Swaps

Balance at January 1, 2008		$	30,526
Total gains or losses (realized/unrealized):
	Included in other comprehensive deficit		3,245
	Included in regulatory assets and liabilities		(33,771	)

Balance at March 31, 2008		$	—

	Regulatory Assets				Liability Derivatives

	Balance Sheet Location	Fair Value			Balance Sheet Location	Fair Value
Derivatives designated as hedging instruments under SFAS No. 133:
Commodity contracts (Natural Gas Swaps)	Receivables	$	35,440		Other Current Liabilities	$	35,440
Commodity contracts (Natural Gas Swaps)	Receivables		(8	)	Other Current Liabilities		(8	)

Total Derivatives designated as hedging instruments under SFAS No. 133		$	35,432			$	35,432

	Accumulated Other Comprehensive Deficit

	Interest Rate Swap Arrangements			Available-for-sale Securities			Total
	(dollars in thousands)
Balance at December 31, 2007	$	(32,806	)	$	115		$	(32,691	)

Unrealized gain/(loss)		—			(2,553	)		(2,553	)
Realized deferred loss		32,806			—			32,806

Balance at March 31, 2008	$	—		$	(2,438	)	$	(2,438	)

Balance at December 31, 2008	$	—		$	(1,348	)	$	(1,348	)

Unrealized gain/(loss)		—			175			175

Balance at March 31, 2009	$	—		$	(1,173	)	$	(1,173	)

		Patronage Capital and Membership Fees		Accumulated Other Comprehensive Deficit			Total

		(dollars in thousands)
Balance at December 31, 2005		$	479,308	$	(35,498	)	$	443,810

Components of comprehensive margin in 2006
	Net margin		18,201		—			18,201
	Unrealized gain on interest rate swap arrangements		—		6,326			6,326
	Unrealized gain on available-for-sale securities		—		184			184

Total comprehensive margin								24,711

Balance at December 31, 2006			497,509		(28,988	)		468,521

Components of comprehensive margin in 2007
	Net margin		19,061		—			19,061
	Unrealized loss on interest rate swap arrangements		—		(4,222	)		(4,222	)
	Unrealized gain on available-for-sale securities		—		519			519

Total comprehensive margin								15,358

Balance at December 31, 2007			516,570		(32,691	)		483,879

Components of comprehensive margin in 2008:
	Net margin		19,259		—			19,259
	Realized deferred loss on interest rate swap arrangements		—		32,806			32,806
	Unrealized loss on available-for-sale securities		—		(1,463	)		(1,463	)

Total comprehensive margin								50,602

Balance at December 31, 2008		$	535,829	$	(1,348	)	$	534,481

	Interest Rate Swap Arrangements			Available- for-sale Securities			Total

	(dollars in thousands)
Balance at December 31, 2005	$	(34,910	)	$	(588	)	$	(35,498	)

Unrealized gain		6,326			184			6,510

Balance at December 31, 2006		(28,584	)		(404	)		(28,988	)

Unrealized gain		(4,222	)		519			(3,703	)

Balance at December 31, 2007		(32,806	)		115			(32,691	)

Realized deferred loss		32,806			—			32,806

Unrealized gain (loss)		—			(1,463	)		(1,463	)

Balance at December 31, 2008	$	—		$	(1,348	)	$	(1,348	)



Cobb EMC	12.8	%	13.3	%	13.9	%
Jackson EMC	11.4	%	12.3	%	11.8	%
Sawnee EMC	10.4	%	10.0	%	N/A	(1)

	Balance at 12/31/07		Liabilities Incurred (Settled)			Accretion		Change in Cash Flow Estimate			Balance at 12/31/08

	(dollars in thousands)
Nuclear decommissioning	$	256,408	$	—		$	16,626	$	—		$	273,034
Other		8,918		(60	)		523		(957	)		8,424

Total	$	265,326	$	(60	)	$	17,149	$	(957	)	$	281,458

	Balance at 12/31/06		Liabilities Incurred (Settled)			Accretion		Change in Cash Flow Estimate		Balance at 12/31/07

	(dollars in thousands)
Nuclear decommissioning	$	240,793	$	—		$	15,615	$	—	$	256,408
Other		8,782		(418	)		554		—		8,918

Total	$	249,575	$	(418	)	$	16,169	$	—	$	265,326

	Hatch Unit No. 1		Hatch Unit No. 2		Vogtle Unit No. 1		Vogtle Unit No. 2

	(dollars in thousands)
Year of site study		2006		2006		2006		2006
Expected start date of decommissioning		2034		2038		2027		2029
Estimated costs based on site study:
In year 2006 dollars	$	154,000	$	199,000	$	160,000	$	198,000

	Range of Useful Life in years*	2008	2007	2006

Steam production	49-65	1.42%	1.47%	1.47%
Nuclear production	37-52	2.39%	2.42%	2.44%
Hydro production	50	2.00%	2.00%	2.00%
Other production	27-33	3.03%	3.00%	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%